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.

Hydraulic fracturing has evolved as the preferred completion strategy for low-permeability reservoirs in India. Hence, a hydraulic fracturing technique that maximizes production and is also operationally efficient will provide an optimum solution for the development of these reservoirs. A channel fracturing technique recently applied to more than 20 treatments for various operators in different fields and reservoirs in India has been delivering superior production results and has proved to be operationally more efficient compared to conventional hydraulic fracturing operations performed in India. Proppant is pumped in pulses at the surface during the channel fracturing technique. These pulses create stable channels within the hydraulic fractures thus decoupling fracture conductivity from the proppant pack itself which result in providing near-infinite fracture conductivity. An earth model was prepared from petrophysical measurements including acoustical data which allowed for the calculation of stresses that are required for hydraulic fracture modelling. These preliminary models were further calibrated based on pressure data gathered during fracture diagnostic tests and this calibrated model was used for the final treatment design. Post-treatment production evaluation was performed by applying nodal analysis and by comparing actual production with predicted production from a reservoir simulator. Treatment evaluation indicated higher fracture conductivity for channel fracturing technique than that of conventional treatments and this led to higher production. Fracturing fluid recovery has also been higher as compared to conventional treatments. Screenouts were eliminated on the treatments that applied the channel fracturing technique. This allowed fracturing zones that might not have been completed with conventional treatments. The amount of proppant pumped per stage has been reduced by nearly 50% as compared to conventional treatments and treating pressures in general have been lower which has led to lower horsepower consumption on the treatments. These successful hydraulic fracturing treatments have confirmed the applicability of the channel fracturing technique in the low-permeability reservoirs of India. This paper presents channel fracturing treatments that have been performed for the first time in India including treatments performed with heated fluid expanding the envelope for the technology application. This paper identifies a solution for screenouts during hydraulic fracturing treatments while maximizing production from low-permeability reservoirs.

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.

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.

Field G in Upper Assam, India is a highly faulted basin, under decline phase since its first production in 1974. The region is characterized by heterogeneous distribution of in-situ stress, depleted pressure gradient (0.25psi/ft) and low permeability (<1mD). Previous conventional fracturing attempts in the area were unsatisfactory. This paper describes the lifecycle of production enhancement project carried-out in this field starting from fit-for-purpose candidate selection methodology to implementation and success of infinite conductivity channel fracturing. Reducing pressure drop within fracture and enhancing fracture effectiveness is fundamental to take the production to next level in this field. Meticulous well-centric-study approach was implemented to rank 5 best candidate wells (including injectors) from plethora of wells lying in tectonically complex field. Formation petro-physical properties and off-set wells data was interpreted to synthesize mechanical-earth-model for selected wells. Detailed geo-mechanical formation evaluation using various Injection tests and Planar-3D model were applied to decide correct well completion and fracturing technique. Best practices were developed to overcome inherent challenges of this region involving deep, tight sands with mid-field tortuosity and high-pressure operations. This study specifies the results of over 15 injection tests (Step Rate tests, Re opening tests, Calibration injection tests) carried out in the field and how the injection test methodology was customized from well to well, catering to specific challenges from each well. By understanding the unique pressure decline response from the formations, insight was gained into rock deformation that generated particular stress field during the geologic past. The fluid leak-off response, rock mechanical properties and net pressure development in Calibration injection were used to estimate the final fracture geometry. An all-inclusive approach for well completions and the use of channel fracturing instead of conventional fracturing techniques have reduced the screen-out risk, ensured successful fracture placement and increased production up to 100% increment in oil. The Oligocene-Eocene aged reservoir facies, marred by various strike/slip faults has developed an uneven stress regime in this field that makes fracturing treatments very challenging. The paper covers a comprehensive research on the analysis of first-ever-application of channel fracturing in Assam basin. This study incorporates a novel practical guide to address issues of multiple complexities occurring simultaneously in a reservoir like presence of tectonic stress, fracture misalignment and high tortuosity.