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.

Poor conformance is a major concern of Mangala, Bhagyam & Aishwarya (MBA) fields. The presence of high permeability streaks or thief layers between injection and production wells typically results in pre-mature water breakthrough, high water cut and deficient volumetric sweep. As a result, significant oil volumes in the reservoir may not be contacted by the injection fluid. Another concern is of low VRR (Voidage Replacement Ratio) in some of the layers due to reduced injectivity in those sands. Consequently, it has led to poor recovery from those sands. It is also a growing problem with the polymer deposition taking place in the wellbore particularly Mangala (undergoing full-field polymer flooding), leading to challenging wellbore cleanup operations. Several methods have been used in the past, both mechanical and chemical to improve the treatment fluids during stimulation. In this paper, we introduce a novel placement technique for Conformance Improvement which is practical, effective and durable as well as another tool variant that helps cleanup challenging wellbore environments. Typically, prior to the tool allowing for pin-point placement, the adjustable nozzle tool is run to ensure that the perforation and wellbore is cleaned up thoroughly with help of advanced fluid dynamics. The dynamic injection modulation (hereinafter referred to as, "DIM") tool for pin-point stimulation placement improves the distribution of injected fluid in the reservoir matrix by the process of dispersion. The tool generates an energized fluid pulse that allows fluid to be diverted away from established fluid paths. The pressure pulse, as it travels dilates the pore spaces thus propagating the wave further into the reservoir. The pin-point accuracy of placements leads to treating of reservoir layers which are left untreated during conventional stimulation treatments where viscous fingering effects dominate. As a result, injection fluid would divert into uncontacted layers to improve sweep efficiency. The other advantage of the tool is the relatively easy integration of tool with existing infrastructure. The tool is easily run with coiled tubing ("CT") with only addition of an accumulator unit on surface. This paper will document the tool physics, job design and Implementation technique for stimulation using Fluid Modulation tool as well enhanced well cleanup. Particular attention is paid to multiple injector and producer well stimulation case studies from these fields, the challenges faced, the solution proposed, and finally the results obtained. The results observed across the field with respect to injection performance is consistently greater than 75% over conventional methods used earlier. Also specifically, in scenarios of difficult fill cleanups, the advanced wellbore cleanup tool variant helped in multiple polymer and sand fill environment cleanouts over various wells over conventional methods of cleanup.

Cairn India Ltd & ONGC completed a joint venture appraisal of the Barmer Hill (BH) field in the Rajasthan block of India in 2015. The objective was to evaluate the effectiveness of horizontal multi-frac completions. The Barmer hill field is a moderate permeability (0.5 – 4 mD) oil bearing porcellanite with alternating sequences of tight shale. To produce this reservoir economically, hydraulic fracturing was the obvious choice of stimulation and was performed on a number of vertical wells (see Shaoul et al. 2007). To better evaluate the development strategy, completions using either transverse or longitudinal fracture treatments were successfully designed, executed, and evaluated. In the appraisal phase, four vertical and four horizontal wells were drilled to appraise the Barmer Hill reservoir in the Mangala field. Two of the horizontal wells were drilled along the maximum horizontal stress direction and completed with multiple hydraulic fracturing stages, which generated longitudinal fractures along the lateral wellbore. The fracture orientation with respect to the wellbore was confirmed with micro-seismic monitoring. This fracture treatment strategy provided the opportunity to decrease the number of frac stages and exhibited lower treating pressures as predicted by standard elastic rock mechanics theory. While the initial productivity of the transverse fractured wells was expected to be almost 2.5 times more than the longitudinally fractured well, it only produced about 40% more. In addition, the EUR of the longitudinally fractured well is almost the same as the transversely fractured well. Based on the generated fracture geometry, theoretically these longitudinally fractured horizontal wells may also provide better effective sweep efficiency when converted to a water injector from a field development concept.

An appraisal well in the KG Onshore Block (a joint venture of Cairn India Ltd and ONGC) has provided key engineering and operational learning's. The objective of this well was to appraise two separate low permeability reservoirs (~ 0.1md) which are ~4300m deep and falls under HPHT conditions. Due to their low permeability; hydraulic fracturing was necessary to verify the production potential of these reservoirs. To cater this, the discovery well was re-designed and sidetracked so that it could handle the expected fracturing loads. Hydraulic fractures (~387,000 lbs of Proppant); biggest in terms of proppant placed in any single stage in India, were executed and then the well was completed with slim-hole selective completion in challenging underbalanced conditions to test these reservoirs selectively. This paper primarily talks about the key constraints while planning and designing this well and then deals in detail on the learnings while executing this unique completion operation. Details on the fracturing design were already covered by Barasia et al. in SPE-171421-MS. The paper concludes with production results and the key reasons which led to ~7 fold increase with respect to previous appraisal well, as observed while production testing.

The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains. The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. . Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.