Abstract
Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs.
During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation.
Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells.
In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.
