The Raageshwari Deep Gas Field, Barmer Basin, India is a low permeability, moderate CGR gas condensate reservoir. It is a low net to gross system with gross reservoir thickness varying from 500-1000m. The pay zone consists of a poorly sorted sandstone interval on top of a stacked volcanic succession of thick lava flow cycles. The wells have been completed with multi-stage hydraulic fracture stimulations to allow production at economical rates.
The major challenge is to improve fracture placement to achieve wellbore connection with the entire net reservoir storage and flow capacity. Connecting each and every net reservoir packet would increase the number of fracture stages and in turn increase the cost significantly. Thus an optimization workflow was generated to increase the efficiency of hydraulic fracturing and reduce the cost of connecting the maximum net reservoir through hydraulic fractures.
An integrated approach including petrophysical and geomechanical analyses was used to identify the potential zones for hydraulic fracturing. Fracturing technologies like limited entry technique using cluster perforation were used to increase the net connected reservoir thickness while employing as few fracture stages as possible. Several post fracturing data acquisition programmes were conducted to estimate fracture parameters such as fracture height, half-length and conductivity to help evaluate the performance of each fracture stage. Single well analytical and numerical models were developed to estimate the impact of connecting maximum net reservoir thickness in terms of both initial production rate (IP) and the expected ultimate recovery (EUR) of the reservoir.
The limited entry fracturing technique with cluster perforation used in several wells was helpful in connecting the maximum net reservoir in the thick gross pay sections present. Based on a cost-benefit analysis, the number of fracture stages for each well was optimized with the goal of connecting the maximum net reservoir thickness to the wellbore. The fracture height achieved in each fracture stage was verified through micro-seismic, RST and temperature log measurements and pressure transient analyses. Once the height was ascertained, other parameters were obtained from post-fracturing pressure matches and pressure build up data. The estimated impact of connecting the maximum net reservoir storage and flow capacity as compared with the initial plan of 4-5 conventional single perforation hydraulic fractures is estimated to be production of ~5% GIIP in 15 years.