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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.

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Coiled tubing (CT) sand plug operations associated with multistage fracturing operations in high-pressure/high-temperature (HP/HT) wells are very challenging, in part because of the small number of such jobs that have been performed worldwide. The wells in "A" field in India have HP/HT formations, with a bottomhole temperature (BHT) of 310°F and a reservoir pressure of 9,000 psi. Although millable bridge plugs are preferred industry-wide, this case illustrates how sand plugs become a suitable alternate solution for multistage stimulation to address space limitations, equipment and completion restrictions, and small tubing sizes, even in challenging downhole conditions. This study provides solutions to operational challenges of low injectivity and completion restrictions, which preclude bullheading and use of conventional bridge plugs. Simulations were sensitized to identify the best solutions for sand settling time, HP/HT conditions, pumping rates, CT speeds, and cleanouts where calcite or scale deposits on sand hinder bottomhole assembly (BHA) penetration. Best practices are given for sand plug operations in challenging HP/HT environments; those best practices can be applied as a reference to design, prepare, and safely perform CT sand plug jobs in such conditions around the world. To address operational challenges in the cases presented here, the first three stages were bullheaded and the last two (a total 325-m sand plug) were placed using CT. Wireline was run to verify CT sand plug tag at ×200-m measured depth (MD). After the successful refracturing job, the 340-m sand plug was cleaned out, followed by acid spotting and squeeze using CT to rejuvenate the lowest zone. Strict application of the recommendations prevented the occurrence of operational contingencies, such as stuck CT, sand bridging, and settling of sand in surface equipment.

Deviated wellbores are more common-place in the industry in recent years as Maximum Reservoir Contact (MRC) is the preferred strategy in wellbore construction. These high-angle, tortuous wellbores, however, have now limited the artificial lift options to Electric Submersible Pumping systems which are capable of sustained life cycles in high-watercut, low-pressure, and/or low-rate completions. Production logging and Coiled Tubing intervention in multi-layered completions and/or multi-compartment horizontal laterals equipped with Electrical Submersible Pumping systems has customarily been a major challenge, especially when the bypass fluid velocities are below the motor-cooling threshold for a conventional Y-tool configuration.An innovative design comprising of a shrouded Electric Submersible Pump with Y-tool combination is able to facilitate access to any completion that requires production logging and/or CT intervention. At relatively low fluid rates, the shroud over the Electric Submersible Pump increases the fluid bypass velocity alongside the submersible motor for the required cooling. This shrouded Electric Submersible Pump configuration is conventionally used where the production flow rates within the wellbore are insufficient to generate the fluid bypass velocities necessary for optimum motor cooling. The Y-tool in other completions allows access for any type of wireline or Coiled Tubing-conveyed intervention for surveillance and and/or treatment operations. Previously, if a completion required a shrouded ESP, conventional Y-tools were precluded, due to the limitation of the production casing inner diameter. A specialty Y-tool was designed to accommodate conventional bypass tubing that has sufficient internal clearance for standard wireline tools together with a crossover adapter for the ESP shroud.This combination of conventional bypass tubing and Electric Submersible Pump shroud in the same wellbore, is limited to 9 5 ⁄8Љ casing where the shroud outer diameter and the bypass pipe outer diameter must have sufficient clearance between each other and sufficient stand-off from the inner diameter of the production casing. The Electric Submersible Pump shroud ensures optimum motor cooling and extended system run life, especially at lower flow rates.This innovative technology is now scheduled to be standard equipment in all Electric Submersible Pump completions in production casings with Outer Diameter equal to or greater than 9 5 ⁄8Љ. Diagnostic wireline and Coiled Tubing-conveyed surveys, remedial and stimulation treatments can now be performed thru-tubing in Electric Submersible Pump completions without costly rig workovers. The availability of these services affords timely intervention to arrest increasing watercuts in Waterflood offtake producers thereby reducing the overall baseline production decline rate.