Abstract The Ensign Field is located in UK offshore licence Blocks 48/14a, 48/15a and 48/15b. The field is located 100 km east of the Humberside coast within the Sole Pit area of the Southern North Sea. The reservoir consists of sandstones of the Permian Rotliegend Group (Leman Sandstone Formation). Reservoir quality has been impacted by diagenesis during deep burial, whereby illitization has reduced permeability to sub-millidarcy scale. The field has been developed with two horizontal production wells, both completed with five hydraulic fracture stages. First gas from the field was achieved in 2012 via the Ensign normally unmanned installation and exported through the Lincolnshire Offshore Gas Gathering System. The field is compartmentalized by multiple regional-scale De Keyser fault zones. A heterogeneous natural fracture network exists with only a limited contribution to flow. Well performance and ultimate gas recovery have been lower than originally anticipated due to sub-optimal completions and a higher degree of compartmentalization than originally expected. The volume of gas that is connected to the wells is limited by low-offset faults, which have been identified by integrating long-term production data, and core, log and reprocessed seismic data. Production ceased in 2018 when the original export route was decommissioned.

Abstract The Ensign Gas Field is located in the Sole Pit basin in the Southern North Sea. The reservoir is the Rotliegend Group Leman Sandstone Formation of Lower Permian age and comprises sediments deposited in an arid continental environment. The main gas-bearing interval in the field consists of sabkha, waterlain and minor aeolian sands, reflecting deposition in an erg margin/lake margin setting. The poor primary reservoir quality of these sands has been severely reduced by extensive illite cementation resulting in average air permeabilities of <1 mD. Attempts to develop the field economically utilizing fracture-stimulated vertical wells has met with mixed results, with flow rates of 14 MMscf per day and lower being measured during testing. The most recent appraisal well drilled on the field was a long horizontal well that was stimulated with five hydraulic fractures resulting in an economic flow rate of 44 MMscf per day. Analysis of the core and log data acquired during the appraisal of the field has shown that the reservoir contains a heterogeneous distribution of fractures, faults and micro-faults. The fracture population is dominated by conductive north–south striking fractures, with subordinate NNW–SSE resistive fractures and NE–SW mixed fractures that are arranged in clusters, with zones of high and low fracture density. Well results to date suggest that the NE–SW open and partially open fractures observed in core do not improve reservoir productivity, but those orientated north–south that are conductive appear to improve well deliverability.