The Triassic–Jurassic petroleum system reserves in Krishna Godavari Basin are found at 3500 to 4500 m depth with bottomhole static temperature (BHST) ranging from 270 to 340°F. Hydraulic fracturing is required to produce economically from these wells because the in-situ permeability of these sands is in the range of ~ 0.01 md. Hence, after perforations, minimal production is observed or the flash production from these wells dies out in a short time span. Between 2010 and 2017, several appraisal wells were drilled and completed using hydraulic fracturing in the onshore Krishna Godavari Basin. However, the success rate of effective fracture placement and sustained production enhancement due to hydraulic fracturing was limited. This was attributed to insufficient understanding of rock mechanical properties and lack of a refined fluid fracturing system despite using a superior fluid system like carboxymethyl hydroxypropyl guar (CMHPG) with organometallic zirconate-based crosslinkers. In 2018, nine wells were successfully hydraulically fractured, and sustained production from these wells was established using a simple borate-based crosslinked fluid system. A key change for the field was rather than designing and pumping fracturing fluid based on only BHST, one of the critical components that led to better proppant placement is the stable fracturing fluid that was fine tuned for the well based on factors like change of source water, tubular shear exposure time for designed fracturing treatment pumping rate, and hydrocarbon properties. This combination of rock mechanical properties and fracturing fluids used is captured as the efficiency of the fluid system, and this governed the usage of fluid loss additives, again a novel introduction for the field. Finally, the key to producing these sands was adequate cleanup and minimal guar residue to maximize the proppant pack conductivity. The paper also discusses the strategy to design fluids with minimal guar loading to reduce polymer retention and to achieve maximum fracture fluid recovery. This robust management of fracturing fluids along with understanding of rock mechanical properties can be seen in the post-fracturing production results.

An intraplate earthquake of magnitude (M c) 6.9 (Anon 2001a) struck Bhuj and the adjoining region of Kachchh in Gujarat on January 26th, 2001 at about 0316 hrs (GMT) and was followed by a number of aftershocks. The epicentre of this earthquake was located at 23.4 • N and 70.28 • E close to the Kachchh mainland fault. The intensity observed around the epicenter was X on the MSK scale. A study of 531 aftershocks, in the magnitude range of 3.0-5.7, recorded at Vadodara Seismological Observatory till March 31st, 2001 has been carried out and various statistical parameters calculated. The total energy released during the study period is calculated to be 8.2 × 10 14 joule. Sudden occurrence of the main shock without any foreshock in the same tectonic system is a unique feature of this sequence. The b-value (0.86), value of M 0-M 1 (1.2), high M 1 /M 0 (0.89) and high value of the decay constant h (0.91), all support the tectonic origin of the present study.

The plug-and-perf (PnP) method is widely used globally for multistage fracturing operations. With only a few jobs performed worldwide, coiled tubing (CT) assisted PnP operations in high-pressure/high-temperature (HP/HT) wells are largely uncharted and most challenging. The "A" field in India has HP/HT formations, with bottomhole temperature (BHT) of 310°F and reservoir pressure of 9,000 psi. Whereas the PnP method is widely used globally, there are few examples in wells with completion restrictions or whose downhole conditions dramatically increase depth inaccuracies and equipment damage. This study describes how to address challenges such as depth correlation (which affects plug-setting depth accuracy), low injectivity, completion restrictions, and heavy brines (which damage CT). To gain further understanding of operations, simulations are sensitized to identify solutions for pumping rates, HP/HT conditions, well kill fluid, milling, and cleanouts where obstructions hindered BHA penetration. The proposed best practices presented here are for primary CT operations involved in the complete PnP cycle, such as wellbore displacement, well dummy run-drift, setting the isolation plug and milling, acidizing using jetting tools, sand cleanout using gels having best performance in HP/HT environment and motor-mill runs with durable resistance in harsh environment, well kill (using 13.65-ppg calcium bromide), and nitrogen lift. The featured case studies describe operations including seven bridge plugs being set at accurate depths and milled after fracturing; cleanout of a 340-m sand column is also featured, as well as well kills with heavy brines. Optimized operational parameters such as CT speed, pumping rates, and the use of smaller outer diameter bottomhole assemblies doubled operational efficiency during those operations.

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.

The Mandapeta-Malleswaram field in India comprises Triassic-Jurassic age sands found at 4000m– 4500m depth, where reservoir pressure ranges 6,000 psi to 9,500psi with static temperature up to 340°F. This tectonically active basin with strike slip stress regime causes a heterogeneous distribution of in-situ stress which complicates the design and execution of effective hydraulic fracturing treatments. Previous attempts at fracturing from 2013 to 2017 were not successful and geomechanics inputs were different from actual values. This paper describes the lifecycle of a production enhancement project, from construction of a geomechanics-enabled mechanical earth model (MEM) to the successful design and execution of fracturing jobs on nine wells increasing proppant placement by 250% compared to previous hydraulic fracturing campaign and achieving 730% incremental gain in gas production compared to pre- fracturing production. Challenges like fracture modeling in tectonically stressed formations, issues of proppant admittance, and complicated fracture plane growth in highly deviated wells (>65°) were overcome by Geomechanical modeling. The modeling incorporated advanced 3D anisotropy measurements, providing better estimation of Young's modulus, Poisson's ratio, and horizontal stresses, resulting in realistic estimation of closure and breakdown pressure. Fault effects were modeled and taken into consideration for perforation depth selection and estimation of pumping pressure with model update based on extensive Minifrac injections and analysis. This study describes the results of injection tests (step rate, pump in-flowback, and calibration injection tests) carried out in the field addressing specific challenges in each well. Pre frac diagnostic injection and decline analysis was used to calibrate the MEM and tailor the design for every well. Proper job preparation for well completions and extensive stability testing involving a borate-based fluid system has reduced the screen out risk and enabled successful fracture placement. Effective pressure management on the job eliminated the problem with frequent screen outs and led to successful execution of all nine jobs while increasing the average job size from 30 t to ~150 t of proppant per stage. From this project, a practical guide to address issues of multiple complexities occurring simultaneously in a reservoir, such as the presence of tectonic stress, fracture misalignment, fissure mitigation, and high tortuosity was developed for future application in tectonically complex fields.