Paradigm Shift in Drilling to Completion in Unconventional Reservoir, Eastern Onshore, India

Permo-Triassic formations in Mandapetta field from eastern onshore, India possesses historical drilling challenges in terms of wellbore instability, non-productive time and poor hole condition in deep higher stressed formations. Lack of acquiring reliable log data and problems in recovering good quality cores present difficulties in proper formation evaluation and zone selection for testing. Historical well test results in target K-Formation has been not encouraging despite good gas shows during drilling. Estimated formation pressure gradient ranges 1.45sg-1.52sg. Layered shale with coal and tight sandstone in same open hole section pose risks of mud losses and poor cement job. Present study highlights the workflow adopted to improve drilling and completion in open hole section of more than 1000 m with varying lithology being drilled successfully. Advanced 3D anisotropic acoustic measurements acquired are used to estimate anisotropic elastic properties (vertical and horizontal Young's modulus and Poisson's ratio) in the overlying shales. Horizontal tectonics has been determined across stress induced anisotropic layers. This approach provides better understanding of formations and stress distribution. Thomsen Gamma values range 0.1 to 0.4 in shale layers of overburden formations. In order to minimize uncertainty in 8.5inch section while drilling, advanced logs were acquired in 12.25inch hole section to estimate tectonics at well location while constraining ratio of horizontal to vertical Young's modulus and Poisson Ratio in shale layers based on Thomsen Gamma and clay volume. Analysis suggested typical VTI anisotropy of 15%-20% in shale layers. Inverted direct horizontal strain parameters at well location suggested the ratio of maximum to minimum horizontal stress to vary 1.15-1.23. Mud weight used while drilling 8.5inch section ranged 1.49sg1.52sg against the recommended mud weight of 1.50sg-1.52sg while pumping sealing agents to prevent mud losses in coal layers. Flow rate was maintained on lower values to minimize ECD values. Hole condition improved significantly with no issues in logging. Post-drill anisotropic rock mechanics model suggested good quality sandstone in target source formation with usual conventional reservoir in shallower formation. Zone was selected based on permeability, breakdown and completion quality for perforations. Analysis of high-quality sonic slowness helped to identify possible gas reservoir in laminated source rock. There was stress contrast of 2000psi-2500psi among reservoir layers and shale stress barriers. Implemented workflow and successful execution helped to drill the well 5 days earlier than plan with no major drilling incidents. Successful core recovery for Shale Gas evaluation was also possible due to better wellbore quality. Initial testing of K-Formation produced gas with significant improved flow rate by 150% without any stimulation for the 1st time in the history of the field.