Bhagyam is the second largest oilfield discovered to date in the Barmer Basin, India with more than 400mmb of viscous, waxy crude in place. This paper describes the evaluation, design and selection process for the use of the latest generation ICD in non-horizontal wells. Sandface completions comprise sand screens coupled with an ICD. Inflow control was highly desirable due to the oil viscosity variation, high permeability, heterogeneity and adverse mobility ratio and the fact the completions could not be easily accessed below a PCP. Oil viscosity ranges from 20 to 250cp varying with depth. The variation in reservoir thickness, produced fluid viscosity and well productivity required a field adjustable pressure drop capability in the ICD. The ICD had to perform at high viscosity and needed to be tolerant to wax and sand production. The operator's experience in nearby fields observed the benefits of ICDs for providing efficient sandface cleanup in horizontal wells. It was vital to model this system accurately however there were significant challenges as no previous examples of using these devices in non-horizontal wells could be found and the ICD completion had not been modeled in a dynamic simulator for this scale of field development. A dynamic simulation model which included the ICD completion was used to evaluate various completion options. A significant amount of work was performed to ensure the ICD was accurately modeled in the simulator. The simulations showed a long term benefit from using the ICD. To date 22 production wells have been completed with the ICD screen systems. This is one of the first applications of the latest generation ICD in non-horizontal wells particularly on a full field scale. It is also a case study of modeling the ICD completion with a dynamic simulator.

The Raageshwari Deep Gas (RDG) Field in the Barmer Basin, India is a lean gas condensate reservoir, with excellent gas quality of ~80% methane, low CO2 and no H2S. The productive zones are in volcanic rocks and volcanogenic sediments. From a permeability perspective, the RDG reservoir is similar to typical tight gas reservoirs in other parts of the world which cannot be commercially developed without large-scale hydraulic fracturing. Recent RDG hydraulic fracture treatments have been monitored with microseismic mapping technology. The microseismic data was acquired in June 2010 to quantify the trend of hydraulic fracture networks induced in a 5-stage stimulation program. The recorded P and S wave events were subsequently mapped in 3D space by fracture stage (in time) to effectively represent the onset, propagation and trends of the fractures and the extent, overlap or inter-connection of the resulting fracture networks. The initial objective of conducting microseismic mapping was only to calibrate the existing fracture simulator. Earlier hydraulic fracture treatments had been conducted with a conventional gas condensate frac design in mind, with targets of ~100m of frac length and a dimensionless fracture conductivity (FCD) ranging from 5-10. The initial frac schedules were designed with large pad and proppant stage volumes (~275,000lb of 20/40 ISP and 16/30 ISP). The efficacy of these fracture treatment designs was to be verified with the microseismic mapping technology. It was found that RDG does not have the typical tight gas reservoir architecture which was assumed for the initial frac designs, but consists of tight matrix porosity contained within a very complex network of natural fractures and planes of weakness with conjugate jointing. Hence the conventional fracture design was changed to deal with such fracture network for future fracturing campaigns.

The Mangala oil field, onshore Rajasthan, India, is the country’s largest onshore oil producer. The field holds large reserves of high wax viscous crude which have a number of significant production challenges, one of which is an unfavourable oil/water mobility ratio. The FM3 and FM4 sand units in the Mangala reservoir are being developed with horizontal wells and the well design required a completion to manage sand production and the adverse oil to water mobility ratio with a preference for minimal well intervention. These reservoir units are composed of thick high-permeability sandstones. It was recognised that field recovery and production rates would be optimised by the application of the most suitable technologies available in inflow control management. This paper describes the successful implementation of the world’s first hybrid inflow control completion for a high wax viscous crude reservoir, including: the hybrid inflow control device selection, completion design and installation, and post-production logs which confirm the performance of this world’s first completion system.

The Mangala field located in the sparsely populated, remote, undeveloped Thar Desert of NW India, is the country’s largest onshore producing oilfield. The field development includes 100 production (11 horizontal) and 50 plus water-injection wells, all directionally drilled from wellpads. The oil is waxy, low GOR crude, with a pour point above 40 Deg C. Wells are producing up to 12,000 bopd. Completion design challenges included; high CO2 content, high wax appearance temperature, high pour point, high viscosities, possible emulsions, sand production and the need for artificial lift. Hot water was selected as the field wide medium for maintaining flow assurance. A completion design was developed, which allows hot water circulation inside the production annulus with a coiled tubing string run with the production tubing to maintain temperatures above pour point. The hot water supply is also used to provide power fluid to the annulus for jet pumping. Some wells have ESPs installed. Specialized rig setup and well head systems were designed to allow simultaneous deployment of production tubing, heater string, chemical and instrument lines, and ESP cables. The wellhead design ensures that barrier policies are maintained throughout the well construction. Simultaneous running of all completion components warranted a specially designed tubing running system and CT deployment system built into the completion rig. Jet pump power fluid exposes the completion to high loads which also made the completion design quite challenging. This paper describes the successful design and deployment of these innovative completions and wellhead systems. To date more than 100 completions have been deployed successfully and are delivering ~125,000 bopd. All this has been achieved with excellent HSE performance (~970 days of LTI free operation) on the completion rig.

This paper describes the first time selection and successful application of Sliding Sleeve Sand Screens in the open hole completions of the giant Mangala field situated in the Barmer Basin in Rajasthan, India which holds ~1.2 billion barrels (bbls) of oil in place. The field is a multilayer reservoir and has waxy viscous crude with in-situ oil viscosity up to 17 cp. The field is being developed with a hot water flood for pressure maintenance and reservoir sweep. Significant production challenges include; an unfavourable mobility ratio, early water cut, sand production and high pour point. Production well completions with sand screens with sliding sleeves play an important role in the field development, providing a very flexible tool to manage production from individual sand units coupled with open hole sand control. The screens are installed as an open hole completion and swellable element packers provide annular flow control. Intervention costs are kept low, as the field is onshore and the opening / closing of the sliding sleeves are done with relatively cheap onshore well intervention via slickline. Active reservoir surveillance and management in Mangala field will play a key part in maximising reserves and production rates from the field. Sliding sleeve sand screens are an appropriate technology for the Mangala field oil wells. These screens provide options for downhole water control across the formation thus increasing well life and reducing water handling at surface. This paper describes the design and implementation of these completions and how the completions provide optimum reservoir management capability for the Mangala field.