No 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.

Significant hydrocarbon volumes are present in heterogeneous, low permeability, HPHT reservoirs in the Central Graben area of the North Sea. In order to properly appraise these accumulations, an innovative appraisal strategy is required, which has to dovetail with hazard management and cost containment. In order to lower development risks these may include elements such as an extended well test and permanently installed optical distributed temperature sensor (DTS) system to monitor the flow profile.A case history is presented of a recent appraisal well drilled on the Acorn discovery, UKCS block 29/8 in the Central North Sea. Significant STOIIP has been mapped in the continental sandstones of the Triassic-age, Skagerrak formation, where reservoir connectivity and resulting commercial productivity was the key uncertainty. A high-angle well was drilled to maximise reservoir exposure, and completed with a DTS system to monitor inflow from different layers. An extended well test was conducted and 50,000 bbls withdrawn. A data-logging device was left on the wellhead to record pressure build-up. The DTS system provided continuous flow profile information.Well construction, completion and flow testing was successfully achieved on time and budget and was a credit to the meticulous planning and execution by the Centrica wells' team. The required dataset was acquired for the subsurface team, much of it in real-time.Ultimately a decision to not develop the accumulation was taken following evaluation of all data from the well. Data collected showed reservoir connectivity to be too low to support a development. Percolation theory suggests that a threshold value of N:G constrains the reservoir type encountered. The discovery appraised is interpreted to be below this threshold; however the information collected is pertinent for determining the viability of other such discoveries.