Abstract
The reservoir in South Oman – discovered in 1989 – is a 400m thick, tight, micro-porous silicilyte slab encased in salt at a depth of 4000m. The field contains the unique Athel silicilyte formation, some 4 km below the surface and is fully encased in salt as a result of which the reservoir is over-pressured at 800 bars. The Athel formation is sub-divided into 7 zones based on GR and Neutron/Density behavior. All zones are expected to be in hydrostatic communication despite the very low vertical permeability and the intensive layering of the silicilyte.
The crestal area has average matrix porosity of 22%. The permeability of the reservoir is extremely low (typically 1 – 100 μD) due to the fact that the rock mainly consists of micro-crystalline silica with abundant micro-solution seams and concretions/cemented beds and numerous sealing faults and fractures. The oil in this field is very light, low viscosity and volatile (48° API, Pb=260 bar, H2S=1.5%, CO2=2.5%). The application of massive hydraulic fracturing (2-4 frac/per well) combined with the favorable oil properties and under-saturated nature of the oil has made economic primary depletion development possible in this low permeability reservoir with reasonable initial oil rates (100-600 m3/day). Current oil recovery factor is 4.2% and expected to reach 10% through continued primary depletion. In 2007, an assessment of potential EOR applications aimed at improving the UR of the field concluded that MGI (miscible gas injection) via hydraulically fractured wells in the crestal area of the field is feasible, once field pressure has sufficiently declined. PVT experiments have demonstrated that miscibility pressure using its own produced hydrocarbon gas is close to the bubblepoint pressure of 260 bar. Subsequently a phased development was defined, depletion followed by MGI. Pilot injection into 2 patterns (Phase 3A) in the crest of the reservoir, will start end-2014 followed by a 2nd phase of crestal MGI (Phase 3B) by 2022. A final stage could be extension of MGI to the full field. With the application of full field MGI, the recovery factor could reach 40%.
The key risks for MGI are identified as early gas breakthrough, poor sweep, and limited injectivity. The pilot injection phase is designed to prove the MGI concept as well as to address these risks. Learnings and data acquisition from the pilot injection phase are essential for a decision on the future expansion of MGI.
This paper presents a methodology to evaluate this tight sour oil field development including EOR assessment, pilot injection monitoring plans and assessment of over 40 fracced wells.
