Cairn India operated Ravva Field is located offshore Krishna-Godavari (KG) Basin on the east coast of India. The field was discovered in 1987 and was brought into production in 1993 from the Middle Miocene sandstones. Oil production rate reached its plateau of ~50,000 bopd by 1999. The field produced at the plateau rate for ~ 9 years before starting to decline by the end of 2007. Two infill drilling campaigns were planned and executed in 2007 and 2011 to arrest the production decline and add incremental reserves to the field. New infill wells increased production for a short while but failed to arrest the prevailing declining trend. By the end of 2013, Ravva oil production dropped to ~21,000 bopd and was declining by 35–40% per year. Arresting the production decline by finding additional reserves in a mature waterflooded field which had already achieved ~49% oil recovery was a challenge with significant risks. Planning for additional infill drilling targeting areas of undrained oil required an integrated approach with adoption of advanced technologies to minimize risks. A 4-D monitor seismic survey was acquired in 2010 over the Ravva field and co-processed with a vintage baseline survey to identify areas of undrained oil. Separate processing of the 2010 high density 3-D survey provided improved seismic imaging of the subsurface architecture. A high resolution 3-D model was created by using sequence stratigraphic concepts, fault seal analysis studies, detailed property modeling through integration of seismic attributes, log and core data. An integrated subsurface study was initiated in 2011 to identify infill well opportunities in the field. A full cycle of integrated reservoir modeling from seismic to simulation was carried out using advanced technologies and workflows. The integrated study resulted in the identification of several infill opportunities as well as near field exploration and appraisal targets. The Ravva Phase-5 drilling campaign executed in 2014-15 comprising 8 infill, 1 water injector, and 2 exploration/appraisal wells was the most extensive infill campaign in the field's history. Well results from the drilling campaign have been very encouraging. The ten producers drilled in the campaign together added ~18,000 bopd to the field production and they are estimated to improve the field oil recovery by ~3%. By March 2015, when all new wells were brought online, Ravva field production had once again reached 28,000 bopd. The success in near field exploration and appraisal has extended the producing field boundary and has identified upsides that could support future drilling campaigns. The Ravva Phase-5 drilling campaign has showcased the first successful application of a 4-D OBC seismic project in India. New technologies such as 4-D seismic combined with integrated subsurface reservoir modeling can demonstrably arrest production decline in comparable mature oil fields and drive recovery factors closer to the technical limit.

Proposal North Kadi oil field in North Cambay Basin, India has been under production since 1969. The hydrocarbon accumulation in the field is mainly in Middle Miocene sandstone of Kalol Formation having high permeability and strong aquifer support. The development plan of the reservoir had been drawn on the basis of simulation studies carried out at various stages. Recently, remodeling of the field has been done for rational exploitation of the reservoirs. Improved Oil Recovery (IOR) Scheme was formulated after updating the geological model. In-fill drilling of 33 locations were firmed up to achieve the optimal recovery. It envisaged 1.7% additional recovery of in-place oil in 20 years over the primary component of 31.23%. At the time of implementation of the scheme, the field had already produced 20% of 67.0 MMt OIIP. Thirty two IOR locations have been drilled during last three years. As of now, the incremental production from IOR wells is 26% higher than envisaged production profile. The in-fill wells have shown no interference on the performance of nearby wells within their past two years of production history. The drilling and completion cost of the wells break-evened in 20 months. The IOR Scheme involving in-fill drilling rejuvenated the declining trend of a mature oil field. Introduction North Kadi field is a major producer in North Cambay Basin, India. The field was discovered in 1968 and commercial production started since 1969. Hydrocarbon accumulation has been established in multiple pay zones belonging to Early Eocene to Miocene Formations. Middle Eocene sandstone of Kalol Formation is the main producing reservoir having permeability of the order of 500 to 3000 md and strong aquifer support. It holds 95% of in-place oil of North Kadi field. The field development for Kalol pays has been done in phases on the basis of simulation studies. The geological model was build up considering pay sands of Kalol Formation to have a number of layers subdivided on the basis of unit-to-unit correlation for major sand bodies separated by consistent non-reservoir coal/shale in between. Recently, geological model of Kalol reservoirs has been revised by integrating additional petro-physical, core and electro-log data, which indicates that the pay units are not in hydro-dynamic communication. This necessitated to consider each unit as independent entity and hence treated separately for optimum exploitation. The revised classification of the pay units and their mapping has not only helped to resolve the apparent anomalous production behavior of the wells, but also helped in setting the strategy for rational exploitation of the reservoirs. Improved Oil Recovery (IOR) scheme was implemented during the period 2000–2003. Geological Setup Cambay Basin is an intracratonic graben trending NNW-SSE. In northeast, it is flanked by Aravali ridge, on its east and south by Deccan craton. It is bounded on both the sides by basement margin faults. Cambay Basin is divided into four tectonic blocks, namely Ahmedabad-Mehsana, Cambay-Tarapur, Jambusar-Broach and Narmada blocks from north to south (Fig.1).

The North Tapti field is located in Arabian Sea WNW of Mumbai city. The bathymetry of the area is very shallow between 8-35 m depending on the tide condition and therefore poses adverse logistic conditions due to strong bottom currents. In North Tapti field shallow gas sands of Oligo-Miocene age occurring at depth of 550- 900 m are layered reservoir with several pays. Exploratory wells produced dry gas with sand. The lithology of the reservoir sand is mainly medium to fine grained and at places coarse sandstone with fair inter-granular porosity. Initial development plan envisaged exploitation of gas through six development wells. All the six wells were envisaged as horizontal wells of about 300m drain hole with sand control completions through pre- drilled liner supported open hole gravel packs with a view to achieve higher gas productivity. The rig positioning activity in North Tapti area experienced great difficulties due to severe sand-scouring of seabed. Therefore, the first well had to be drilled as vertical well and completed with premium screen as a standalone screen completion with a view to make up lost time prior to impending monsoon. Studies based on the drilling data obtained from first development well revealed sub- surface surprises like reduction in pay thickness and occurrence of multi layered pays in Mahim and Daman formations at shallow depth. This posed considerable challenges in achieving desired high drift at shallow vertical depth of about 400m while maintaining high angle trajectory during drilling and subsequent completion programme. Hence, innovative drilling and completion approaches were adopted to tackle sub-subsurface complixities and to achieve maximum planned gas production. In this backdrop of accomplishing the onerous task to produce sand free gas in all the six wells in platforms of North Tapti which were planned to be completed with suitable sand control methode using in-house expertise was a real challenge. The methodology adopted in two wells viz. A and B of 80° and 85° inclination were single frac pack and stacked completion of both. Stand alone in the lower barefoot section and a frac pack in the upper sands which was cased cemented and perforated. The wells of P1 platform are accessible with difficulty due to severity of water depth and short tide periods. Therefore wells were completed as stand-alone screen completions through Expandable Sand Screen (ESS) in 6″ drain hole section and 7″ liner sections. This highly innovative drilling and completion approach facilitated exposure and completion of thin pay sands in multi-layered reservoirs in a deviated well. The result is stable and uninterrupted gas production for over a period of more than two and half years and continuing at a consistent rate of about 1.3 MMm3/d.

The Mangala field is located in the northern part of the onshore Barmer Basin in India. The Fatehgarh Formation is the primary reservoir, which was deposited during the rifting phase that created the Barmer Basin during the late Cretaceous to early Palaeocene period. The majority of reservoired oil is contained within the Upper FM1 member of the Fatehgarh Formation, composed of single storey and multi-storey stacked, meandering channel sands. These sands vary in thickness from 3 to 7 meters, with net-to-gross ranging from 18% to 78%. Well-based correlation of flood plain shales and fluvial sands in such a heterogeneous fluvial system poses a major challenge for reservoir characterization. These thin fluvial channel sands are not resolved in the conventional seismic data, which makes it difficult to map the lateral continuity of these sand units. Sparse-layer Inversion was performed on the 3D stack PSTM data, which resulted in a dataset with improved detectability and resolution. Results were validated using well log and production data. Amplitudes of the high resolution seismic data provided information on sand continuity and connectivity. Consequently, Colored Inversion was performed on this data which provided improved understanding of the lateral distribution of the thin FM1 channel sands.