[1] New constraints on pressures and temperatures experienced by rocks of the Himachal Himalaya are presented in order to test models for the emplacement of the Himalayan crystalline core here. A variety of methods were employed: petrographic analysis referenced to a petrogenetic grid, exchange and net-transfer thermobarometry, Ti-in-biotite thermometry, and analysis of quartz recrystallization textures. Rocks along three transects (the northern Beas, Pabbar, and southern Beas transects) were investigated. Results reveal spatially coherent metamorphic field gradients across amphibolite-grade and migmatitic metamorphic rocks. Along the northern Beas transect, rocks record peak temperatures of~650-780 C at low elevations to the north of~32 10' N; rocks in other structural positions along this transect record peak temperatures of <640C that decrease with increasing structural elevation. Rocks of the Pabbar transect dominantly record~650-700 C peak temperatures to the east of~77 55' E and~450-620 C peak temperatures farther west. Peak temperatures of~450-600 C along the southern Beas transect record a right-way-up metamorphic field gradient. Results are integrated with literature data to determine a metamorphic isograd map of the Himachal Himalaya. This map is compared to metamorphic isograd map pattern predictions of different models for Himalayan crystalline core emplacement. This analysis excludes models involving large magnitude (>20-30 km) extrusion and permits (1) models involving small magnitude (<20-30 km) extrusion that is discontinuous along the orogen and (2) tectonic wedging models, in which the crystalline core was emplaced at depth between a sole thrust and a back thrust in the Early-Middle Miocene.

The HC field was discovered in 1972 and put on commercial production in 1974. The field’s oil production reached life-time high of 461 tpd (tonnes per day) in June, 2006. However, soon the production started declining, rather rapidly, and average production during 2009-2010 was mere 220 tpd, which necessitated an integrated review of the field, combining geosciences, reservoir engineering and production technology. Study started with organizing abundant and scattered field data, recording of Cased Hole Formation Resistivity (CHFR) / Reservoir Monitoring Tool (RMT) and Cased Hole Compensated Neutron (C/H CNL) logs in key wells, which tagged shifted fluid contacts and modified saturations. Past performance of the sands was studied and reservoir simulation carried out for obtaining suitable perforation policy for sands with GOC and OWC. Shale/coal barriers were identified and their reliability was tested for two reservoir units, which helped in putting the rim of oil between GOC and OWC on production. Based on the integrated study, opportunities were identified and well interventions through work-over jobs were carried out for recompletion, zone transfer and water shut-off. Geology of the main block was redefined integrating seismic and new data gathered from four strategically newly drilled wells. Further, a strategy was firmed up for rational exploitation of all sands in the multi-layered block aiming at maximising recovery and minimizing development and operating cost. Implementation of the study augmented field’s production to a second plateau with increase in production from 220 tpd to 375 tpd.

Prediction of fracture porosity and permeability remains a challenge for fractured carbonate reservoirs. As natural fractures are heterogeneous and subseismic in scale, core data and image logs only provide partially sampled data, leading to sparse information on fracture length, height, orientation, spacing, and aperture. In the present study, an integrated discrete fracture network was generated that is capable of predicting fracture porosity in Eocene carbonates of the Bengal Basin in northeastern India. The predictive fracture modeling method used 3D kinematic and geomechanical restoration of interpreted seismic horizons to estimate infinitesimal stress and strain values and to characterize associated fracture sets. Seismic attribute analysis was used to extract faults and fractures from an ant-track cube, which provided sharper definition of discontinuities seen in conventional curvature attribute data. An integrated discrete fracture model was created using information from seismic attributes, seismic inversion, and strain distribution to determine fracture intensity. Faults and fractures that are seismically resolved were statistically analyzed, which indicated that spatial distribution of fracture length follows a power law. Based on theoretical concepts of fracture mechanics, linear aperture-to-length scaling was used to characterize aperture population. A present-day geomechanical earth model was used to identify open fracture sets. This model shows that northeast–southwest-oriented fracture sets are critically stressed and will contribute to porosity and permeability. Criticality of fractures to shear failure was analyzed by computing geomechanical parameters — slip stability and dilation tendency, based on the direction and magnitude of far-field stresses. Fractures with slip and dilation tendencies greater than 0.6 in the modeled discrete fracture network were taken as inputs for porosity and permeability estimation.