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.