TITLE:
Optimizing Recovery Strategies in the Brent East Reservoir of the Alwyn North Field: An Integrated Simulation and Economic Assessment
AUTHORS:
Franck-Hilaire Essiagne, Moussa Camara, Kouassi Louis Kra
KEYWORDS:
Brent East, Reservoir Simulation, Natural Depletion, Water Injection, Immiscible Gas Injection, Water-Alternating-Gas, Economic Evaluation, ECLIPSE E100
JOURNAL NAME:
Open Journal of Applied Sciences,
Vol.16 No.8,
August
20,
2026
ABSTRACT: This study presents an integrated reservoir-simulation and discounted-cash-flow assessment of recovery strategies for the Brent East panel of the Alwyn North Field in the UK Central North Sea. The work uses an ECLIPSE E100 three-dimensional black-oil sector model representing the Brent East panel rather than a complete proprietary full-field model. The corner-point grid contains 36 × 51 × 18 geometrical blocks; the upper zero-porosity interval is inactive, leaving 17 effective reservoir layers representing Tarbert 3, Tarbert 2, Tarbert 1, Ness 2, and Ness 1. Four selected development cases were compared over a 15-year forecast: natural depletion, peripheral water injection, immiscible lean-gas injection, and time-controlled water-alternating-gas injection. The selected natural-depletion case, using five producers and a 5% critical gas saturation, yielded a recovery factor of 26.68%. Water injection with five producers and four injectors increased recovery to 48.61% by maintaining pressure and improving areal sweep. The selected gas case, using three producers and two injectors, achieved 28.16% because early gas breakthrough and an unfavorable gas-oil mobility ratio limited volumetric sweep. WAG, using five producers and six injectors with water and gas assignments switched every two years, delivered the highest technical recovery of 50.73%. Economic results show that water injection has the highest NPV ($1785MM) and IRR (34.78%), whereas gas injection has the shortest payback period (3.703 years). WAG remains technically superior but requires greater investment and operational complexity. No complete observed pressure, oil-rate, water-cut, or GOR time series was available; therefore, the model was not formally history matched, and the results are interpreted as comparative development-screening forecasts. The study demonstrates the value of combining transparent model description, operationally constrained simulation, and economic screening when selecting recovery strategies for heterogeneous Brent-type reservoirs.