Grover, Kavish (Cairn Oil & Gas, Vedanta Limited) | Kolay, Jayabrata (Cairn Oil & Gas, Vedanta Limited) | Kumar, Ritesh (Cairn Oil & Gas, Vedanta Limited) | Ghosh, Priyam (Cairn Oil & Gas, Vedanta Limited) | Shekhar, Sunit (Cairn Oil & Gas, Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas, Vedanta Limited) | Das, Joyjit (Cairn Oil & Gas, Vedanta Limited)
For any typical water flood or polymer flood management, maintaining optimum Voidage Replacement Ratio (VRR) is most crucial for optimizing reservoir performance. In a typical patternflood, a single injector supports many nearby producers, determining its contribution to particular producer is subjective and has inherent uncertainties. To avoid these uncertainties in allocation factor, a novel approach using simulation model based voidage compensation on pattern by pattern basis has been proposed in this paper.
History matched simulation model, which has been sectored into 5-spot producer centric patterns, forms the basis of this study. Voidage replacements are analyzed on these producer centric 5-spot patterns. Sectoral voidage created is determined using change in hydrocarbon pore volume (HCPV), water pore volume (WPV) and production from the sector. Sectoral Voidage Compensation Ratio (or Pseudo VRR) thus calculated is representative of the net change due to injection and production. The advantage is that it does not require any numerical allocation factor, rather is based on fluid movements within a pattern as predicted by the simulation model. This method thus provides a new approach to analyze pattern performance.
Along with VRR, pattern wise recovery and interwell channeling/cycling are the key parameters for any water flood performance analysis. A workflow has been proposed to rank the patterns based on these parameters and categorizing them into problem buckets. Actions corresponding to each bucket have been proposed. This forms the basis of strategizing improvements in well-by-well and pattern-by-pattern performance for optimizing field performance.
Mund, Bineet (Cairn India Ltd.) | Das, Amlan (Cairn India Ltd.) | Sharda, Ruchika (Cairn India Ltd.) | Bhat, Sudeep (Cairn India Ltd.) | Kumar, Ritesh (Cairn India Ltd.) | Gupta, Abhishek Kumar (Cairn India Ltd.) | Shankar, Pranay (Cairn India Ltd.)
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.
Gryphon is an early Eocene age field located in block 9/18b and 9/18a-R of the UKCS North Sea. The field has been on production since October 1993 and comprises basin floor high-density turbidite sandstones within the Balder Formation. The thickly bedded Balder turbidite lobes of the Gryphon Field were remobilized during the early Eocene, probably by a catastrophic event such as an earthquake. This resulted in large-scale modification of the original depositional geometries of the sand lobes and the development of seismic scale sand injection wings.
Initial field development was focused on the in-situ massive turbidite lobes. Since August 2004, production started from wells drilled into the injection wings.
Going forward, oil reserves in the Gryphon area will be developed by active oil rim management and drilling of additional development wells.
New development wells can be divided into two distinctive types: massive turbidite lobe targets and progressively more complex injection wing targets. Massive turbidite lobe targets are dynamic targets, generated through reservoir simulation. For this purpose, a completely new dynamic model has been built. Injection wing targets are less affected by existing production and are mainly driven by seismic observations. Given the complex nature of the remaining injection wing targets, technological developments are aimed at improving the seismic data quality.
The new dynamic model also provides a tool to evaluate the resources and the development strategy for the last phase of the Gryphon Field, gas blowdown.
Recent development drilling on the field and recognition of future potential, has allowed further facilities and topsides work to be carried out. This will allow the Gryphon Alpha FPSO to remain on station longer. It is the longest serving permanently moored FPSO in Europe and following the topsides work, the Vessel Class has been extended to early 2013.