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The Krishna-Godavari high-pressure/high-temperature (HP/HT) basin, India, has various hydrocarbon fields from Triassic-Jurassic age with very tight sands (0.01md), bottomhole temperature of 350°F, and bottomhole flowing pressure of 9,500 psi in a normal to strike-slip geological regime. The only sustainable way to produce is by hydraulic fracturing, which has been disappointedly attempted over the last decade. The major challenges encountered were unstable fracturing fluid, downplayed role of geology, complex stress environment, and uncharacterized natural fissures. This project used a cutting-edge formation evaluation tool to identify potential of sands. Advanced acoustic study helped in the tectonic strain calibration to build a robust mechanical earth model, further strengthened by pressure-matching with previously executed fractures in the same formation. This helped capture the lateral variation of tectonics and rock properties attributed to fault and lithological changes. This technical advancement was used for modelling fractures in two formations of the block, combining the execution with a superior fracturing fluid composed of fracturing fluids with fast and delayed crosslinked systems used together. Previous attempts in this field were faced with poor proppant placement as well as higher water production due to invasion in the water-bearing zones. The technical improvements in formation testing and subsurface sampling in delineation of potential oil and water zones coupled with a geomechanics-enabled perforation strategy aided the fracturing treatment design to avoid the growth of fracture height in water-bearing zones. The fracturing fluid system used in this project combined borate with zirconate crosslinking, which kept the fluid stable at very high temperatures, decreased the friction loss by management of the crosslinking delay time, and increased the bottomhole stability of the fracturing fluid. Other best practice adopted to execute successful fractures was the execution of a diagnostic injection test methodology for individual stages in the well. Post-injection temperature logs were conducted, and the temperature profile was used to estimate height growth. A closed loop process was adopted in which results from pre-job injections were applied to calibrate the existing data set, for example, the 1D-MEM and fluid leakoff and optimize fracturing design at each step. The key to better fracture placement and higher hydrocarbon production was following a deterministic approach for identification of the oil-water contact (OWC) using a 3D radial probe; getting a better estimate of the fracture geometry by constructing a robust 1D MEM by using a 3D acoustic profiling wireline tool; and, finally, designing fractures to successfully avoid the OWC using the post-injection temperature log to calibrate height growth.

Objectives/Scope Rock fabric characteristics of Gamij Field lies in the purview of conventional reservoirs but are as complex and uncertain as unconventional. It is a multi-layered, heterogeneous reservoir on depletion drive with very low permeability. Even after hydraulic fracturing and artificial lift, the production rate lies in the range of 3-4 m3/d. This paper evaluates the impact of past hydraulic fracture operations and uses this understanding to optimize the stimulation strategy for future wells. Methods, Procedures, Process A customized multidisciplinary modeling and flow simulation workflow; integrating petrophysical, geomechanical, stimulation and production data was adopted and applied to sectors of the field. Two techniques were combined 1. Unconventional (Fast Loop) 2. Conventional (Slow Loop) in an intriguing and iterative manner. Hydraulic Fractures were designed, optimized and calibrated using a rigorous workflow of unstructured grid and unconventional fracture modelling/3D planar fractures in the sector models. Sector model is considered the most effective approach to characterize completion quality in Gamij Field due to the limitation of current modelling technologies to design and simulate hydraulic fractures in full-field model. Results, Observations, Conclusions The results of sector model is validated with full field model and a number of iterations were performed to match pressure from the result to the initially assumed in creation of 3D MEM (Mechanical Earth Model). Reservoir quality (RQ) estimation is affected by complex mineralogy including abundance of iron and titanium rich sediments. Stress regime shows vertical transverse isotropy nature of shales and suggest re-orientations near to fault zones. There are several areas, especially in the eastern part, where the tectonic regime changes from normal to strike-slip faulting. HF modelling not only explains the contrasting behavior of existing wells, but also discusses alternatives that could help to unlock the true potential of the pay zones. This paper elucidates techniques to maximize reservoir understanding and allow optimization of hydraulic fracture design in terms of casing diameter, job size, and design. Simulations shows multiple fractures were created from different preformation cluster in a single stage treatment. Overall, the case study showcases different factors that govern the development of a tight oil reservoir and the ways to characterize and quantify these uncertainties. Novel/Additive Information This work is the first step to quantify the complex reservoir mineralogy, impact of laminations, depletion, stress variation on the efficiency of HF jobs. Identification of potential sweet spots based on reservoir quality and completion quality indexes, establishing well productivity. The uncertainty cannot be eliminated but it ought to be reduced and risk analyzed before the actual execution.