Raageshwari Deep Gas (RDG) Field in the Southern part of Barmer Basin is a tight gas-condensate reservoir composed of a thick volcanic unit overlain by volcanogenically-derived clastic Fatehgarh formation. This tight reservoir hosts significant gas reserves and is being successfully exploited with the implementation of multi-stage hydraulic fracturing. For optimum hydraulic fracture stimulation, a clear understanding of the geomechanical properties of the reservoir and its seamless integration with petrophysical interpretation is of paramount importance to achieving long-term sustainable well performance. The key geomechanical factors in hydraulic fracturing of deep volcanic reservoirs form a niche subject as opposed to the widely published unconventional shale plays. This paper illustrates the workflow developed for construction of 1D-Geomechanical model in tight volcanics and its application for selecting perforation intervals and designing of frac jobs; its validation through diagnostic fluid injection, execution of hydraulic fracturing jobs and associated challenges. The one dimensional Geomechanical model integrates basic petrophysical logs, dipole sonic data, rock mechanical tests on core, processed image log data with break out analysis, regional tectonic history, existing natural fracture evidences and drilling data. Most importantly, the model is calibrated with field test data such as diagnostic fluid injectivity test (DFIT), step rate test (SRT) and mini-frac data. The workflow involves estimation of rock mechanical properties (Young's modulus, Poisson's ratio, uniaxial compressive strength) based on logs and calibration with core data and documented analogues. The next step is modelling of stresses in the field for identification of current stress regime. Integration of failure models with wellbore image data provides the understanding of maximum horizontal stress. Basic log data is used for estimation of over burden and pore pressure. Calibration of pore pressure is carried out from the DFIT data. The third step involves the assimilation of rock strength model with stress model to estimate minimum horizontal stress. In a geologically complex setting with multiple histories of tilting and faulting, tectonics plays an important role in the existing stresses. All these variables are captured and validated with field test data to construct a useful geomechanical model. As part of the recently concluded hydraulic-fracturing campaign, the 1D-Geomechanical model was successfully applied to identify approximately 125 fracture stages in 20 wells for multi-cluster hydro-fracturing in the field. An effective geomechanical model, along with petrophysical interpretation has proved to be helpful in enhancing recovery, improving frac success rate and ultimately, reducing cost on operations. The approach emphasizes the importance of continuous update of the model to deal with variation within the field area and heterogeneity in volcanic rocks.

The Raageshwari Deep Gas (RDG) Field, situated in the southern part of Barmer Basin, is a tight gascondensate reservoir comprising of Volcanics with basic lava flows (basalts) and stacked silicic pyroclastic flows (felsic) interbedded with basalts, and overlying clastic Fatehgarh Formation. The field is currently being developed using deviated wells with multi-stage hydraulic fracturing. The volcanic rocks pose a significant challenge in reservoir zone identification and trend prediction. Variability in mineralogy, lithofacies, thickness of reservoir subunits and areal distributions of pores/vesicles and fractures results in marked reservoir heterogeneity. This paper demonstrates a comprehensive facies characterization for pay zone identification, building a robust reservoir model and execution of multistage hydro-fracturing. The facies characterization methodology integrates cores, mudlogs (gas shows and chromatographs), wireline logs, hydraulic fracturing and production data. Conventional (sand-shale) petrophysical workflows are not applicable to volcanic rocks that are fundamentally different in nature. Hence a new unconventional work flow was established and validated in pilot wells. It was evident that the key parameter to address would be permeability given the tight nature of the formation (micro-pores). An initial facies classification was conceptualized integrating basic suite of logs and core data. New learnings on well performance behavior were assimilated with NMR log data in further refining the facies model. Higher gas counts and higher productivity was found to be associated with higher NMR bins indicative of larger pores and hence better facies. The pay zones identified based on refined facies model helped in optimizing hydraulic fracturing of around 100 zones in 15 wells in recently concluded Hydro-frac campaign. The pin pointing of better producible zones in an approximately 700 m thick volcanic package facilitated reduction in operational costs. Multiple perforations (clusters) were combined in each fracturing stage; injectivity of individual cluster was checked during mini-frac and post fracture temperature analysis resulting in an optimized hydro-frac job. Production logging was carried out to confirm contribution from stimulated intervals. It was observed that almost all fractured intervals were contributing to production validating the petrophysical work. Improved facies classification was also built into the reservoir model thus improving the property distribution and reservoir predictability away from the wellbore. This study facilitated in building a robust history matched reservoir simulation model for realistic production forecasting. This case study from an unconventional volcanic reservoir emphasizes the importance of integrating different datasets, in unraveling reservoir complexity leading to increased confidence in effective reservoir management. The volcanic reservoirs pose a huge technical challenge for sustained production performance and reservoir management; calling for continuous upgrading of the facies model by aggregating data from hydro-fracturing and newly drilled wells.

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.

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A tight-gas reservoir commonly refers to a low-permeability reservoir that mostly produces natural gas. Irrespective of the reservoir rock type (e.g. sandstone, shales, coal seams or volcanics), they all have one thing in common—these reservoirs cannot be produced at economic rates without an effective hydraulic fracturing treatment. In conventional reservoirs, rock flow capacity is usually sufficient to allow for hydrocarbons flow; therefore, hydraulic fracturing is broadly considered as a remedial technique to improve the productivity of suboptimal producing wells. In this study, fracturing was not originally considered in the primary drilling and completion planning phases, which in many cases limited the effectiveness of fracturing treatments because of challenges resulting from the well architecture, trajectory, azimuthal orientation with respect to dominant stress regimes, and other factors. As the importance of unconventional resources for hydrocarbon production has increased dramatically during the past decade and more attention and efforts are focused globally to explore these reserves, the demand for hydraulic fracturing techniques to prove the economic profitability of these resources has in turn tremendously increased. This has created a paradigm shift, as operators are beginning to recognize that they need to drill and complete wells for hydraulic fracturing to maximize the return on their assets. Therefore, hydraulic fracturing has gained an advanced position in the planning phase of unconventional assets. Volcanic formations are one of the rarer rock types with the potential for accumulations of hydrocarbons that can produce economically. This rarity has resulted in a lack of understanding across the industry on the nature of these reservoirs and how to successfully turn them into lucrative assets. Because of the tight nature of these formations, optimal hydraulic fracturing strategies are intrinsically necessary for economic production. Without a thorough and integrated understanding of the petrophysical and geomechanical properties of these formations, it will be difficult to interpret the fracture growth behavior and its inherent effect on fracture flow capacity in the production phase.