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.

A reservoir with a rare geomechanical setting of higher stresses at shallower depths and vice versa was fractured. The multistage fracture responses were validated using production logging data. Further, production optimization was achieved by understanding the flow profile and geomechanical setting to decide on an optimal flow condition for the wells. An innovative solution-driven approach was identified with production logging playing a key role. Based on the geomechanical model, calculated fracture gradient indicated higher stress in the shallower section and lower stress in deeper intervals. Multistage fracturing was performed. Post fracturing, production logging was carried out in Well A at two different chokes to understand flow behavior in wellbore and correlate with reservoir response. Based on these results, an intermediate choke was selected for production logging in Well B to observe any improvement in flow behavior. An integrated study of geomechanics, fracture performance and production logging resulted in deciding an optimal flow condition for the wells. Results are presented for a two well operation. Production logging results indicated that deeper intervals were producing higher compared to shallower layers, thereby validating the geomechanical model. Also, fissures were encountered during deep stage fractures, indicating potentially high production from reservoir from these stages due to better flow conduit. This was also confirmed from the production logging results. In Well N1, production logging data, in the lower choke, indicated sluggish and unstable flow behavior with the top three stages underperforming. However, at higher choke, a steady and uniform flow was observed. The production logging results were also observed to be in line with the obtained frac-operation parameters on the higher choke. However, an anomaly was observed in the second stage of Well N1, which is estimated to be as a result of fractures closing down due to higher stresses in shallower depths. Based on this, an intermediate choke was selected to flow Well N2 and record production log data to observe and evaluate the flow behavior at a different choke. The flow was still observed to be sluggish and unstable at the intermediate choke. Hence, a final decision was taken based on all the different conclusions to flow the wells at higher choke to maintain optimal frac stage performance and a uniform and steady flow. Rare geomechanical setting of reservoirs presented challenges in accurately characterizing them. The paper recognizes the versatility of the production logging tool in delivering and understanding both reservoir response and wellbore flow conditions. The integration of fracture response with production logging results enabled validation of the reservoir response and provided valuable insights into understanding the flow behavior inside the well, and finally optimizing well productivity.