Exploitation of thin oil zones in a mature field with complex carbonate geology under strong water drive offers many challenges. The primary objective is effective oil recovery from the thin oil zones without excessive water production. The initial development phase targeting thin remaining oil zones in a giant, mature carbonate field in Saudi Arabia has been guided by reservoir simulation results, with performance generally exceeding expectations. However, performance of individual horizontal wells has varied greatly. Multivariate statistical methods have been applied across the gamut of reservoir parameters for these wells to gain further insights into critical success factors and mechanisms. Response variables were established (producing time to reach various watercut thresholds) to gauge well performance. Principal component, factor, and multiple regression analyses were applied to independent reservoir parameters for a population of 20 horizontal wells placed in the target zone. These parameters included zone thickness, standoff from fluid contacts, vertical permeability contrast, thickness of low-permeability interval, reservoir contact, net/gross ratio, completion design, extent of fracturing, zone porosity, proximity to injectors, and trajectory orientation. Multivariate analysis conclusively demonstrated that the principal factor governing well performance in the early period (up to three years) was the vertical permeability contrast or in other words, the extent to which a permeability baffle exists between the thin low-permeability zone and the underlying thick high-permeability zone. Other parameters may contribute to well performance beyond the 30% watercut threshold and will be addressed in a future paper. The findings from this study have been translated into Best Practices for exploiting thin oil zones and have been applied in further developing the thin oil zone in the subject field.
The giant Wafra Field is the largest field in the Partition Zone (PZ) between Saudi Arabia and Kuwait. The Cretaceous Wara reservoir represents one of the most prolific producing zones in the PZ. The Wara is a Cretaceous sequence of channel sands (fluvial/tidal) that have locally complex vertical and a stacking patterns. These sands are interpreted to have been deposited in a tidally influenced lower delta plain depositional environment in a low angle ramp setting characterized by low accommodation space. Stratigraphic complexity is high and in general, sandstone bodies are below seismic resolution. The Wafra Wara reservoir is a structural accumulation formed by a low amplitude anticline with 4-way dip closure, with some structural complexity at the reservoir level, consisting of normal faults with small displacements.
Although the Wafra Wara clastic reservoir is mature, new "sweet spots?? with original formation pressure were drilled recently in the middle of the development area, and there is also still significant remaining oil on the current margins of the field where deeper OWCs have recently been encountered. Increasing water cut and an active aquifer present some challenges to maintaining good oil production in the reservoir, mitigated by production optimization efforts and a rigorous surveillance program.
A comprehensive multidisciplinary study was performed to identify new infill well and workover opportunities within the most mature portion of the field to increase production and recovery. The team reviewed all existing data and performed detailed 3D-seismic interpretation to refine stratigraphy and structure, generate production attribute maps and to understand the production history and current state of the reservoir. Production, well-test data, cased-hole logs and analytical techniques were used to identify areas with by-passed oil and to predict initial rates and incremental recovery for infill wells. Deterministic and probabilistic forecasts were generated using field and offset well decline curve analysis. New opportunities were then ranked based on geological and engineering criteria.
This paper highlights the challenges and lessons learned from this integrated reservoir management study to define remaining oil and to identify opportunities to increase ultimate recovery.