Oil India has a fascinating history going back to India's first oil discovery in 1889 in Digboi, Assam. Today it is an integrated exploration, production, and refining company with 19 drilling rigs, 28 workover rigs, and expertise across the oil spectrum. My guest today is Dr. Ranjit Rath, Chairman and Managing Director of Oil India Limited, a geoscientist and alumnus of IIT Bombay and IIT Kharagpur. He's a proud recipient of the National Geo Award from the President of India and previously headed the Mineral Exploration and Consultancy Limited under the Ministry of Mines. He has worked on applying geosciences in creating India's strategic petroleum reserves, a first-of-its-kind initiative for underground rock caverns for crude oil storage towards energy security.
Dr. Rath, thank you for joining me today. Let me start with something I hope is interesting: as a technologist in oil, what is the most interesting technology you're working on right now, either for finding, processing, or distributing oil in India?
Thank you for having me. From an Oil India perspective, two things: First, after persistent exploration we have established hydrocarbon in the North Bank of the Brahmaputra River. All discoveries so far were on the South Bank, so this is immense. We supplement this with a 3D seismic campaign and also adopt multi-well technology to operate five wells at one point and extended reach drilling (300 to 3500 meters below the river bed with an S or J bend) to target hydrocarbons without vertical drilling.
For those who may not know, there is a history to Oil India and Assam—the first discovery over a century ago. Tell us what you found now in the context of that history.
In 1889, oil was discovered by chance in a place called Digboi. The British were laying a railway line in Assam and elephants carrying sleepers got black liquid on their toenails. They dug there—hence 'Digboi.' That discovery was at about 1880 feet (roughly 50 meters). Today, our discoveries in the South Bank are at 5,700 meters and in the North Bank at 4,600 meters. There are huge possibilities; we need to dive deeper.
Before we get to the Oil India landscape, what made you go back to the South Bank of the Brahmaputra in the first place?
When the government brought in the Hydrocarbon Exploration Licensing Policy (HELP)—a revenue-sharing contract replacing the NELP production-sharing model—it allowed operators to choose large areas. Having explored extensively in the South Bank, it was natural to explore the North Bank. We acquired large areas under the OALP campaign, and this finding is one such result.
Now let's look at the landscape for Oil India. Key activities include drilling, refining, and distribution, but you're also drilling in the Andamans and at six or seven international locations. Tell us about the path Oil India has taken from two decades ago when most activities were in the Northeast.
Oil India had mining leases (PMLs) in the Northeast and in Rajasthan. We secured about 60,000 square kilometers of exploration acreages under the OALP rounds: 10,000 in Rajasthan, 15,000 in Mahanadi-Onshore, 10,000 in Andaman & Nicobar offshore, 5,000 in Kerala-Konkan, plus acreages in Tripura and North Bank Assam. We started seismic campaigns, identified prospects, and drilled. We changed our approach to supplement seismic with petroleum system modeling, which gave us new prospects. In Andaman we plan to drill all four wells; in Kerala-Konkan we may drill a second well if the first succeeds; in Rajasthan we identified more prospects. We are also drilling deeper in the mining lease areas and enhancing well count year on year.
What has changed to bring more efficiency in the process of scouting, zeroing in, and drilling? Is it bigger bets or technology?
Efficiency comes from faster interlocation movement of drilling rigs, top-drive rigs reducing bit change time, handling higher pressure regimes as we drill deeper, and enhanced workover rigs. Our geology, geophysics, and reservoir teams back-analyze to identify new drillable locations—new locations, infill wells, or replacement wells. We tap any reservoir containing hydrocarbon.
You've talked about investing 20,000-25,000 crores in capex, including drilling. What does that add up to in terms of increased barrels per day?
We do techno-economic analysis per field, establish NPV, and assume operational day rates and oil prices. Exploration is risk-bearing. The Andaman campaign is about 2,500-3,000 crores for four wells from 100 m water depth to 4,000 m depth. Discovery could change the narrative. Onshore, we accrete more resource base annually and convert to reserves. Natural gas is equally interesting—we have substantial gas in the Assam shelf and need to tap it.
Previously we lacked evacuation facilities for natural gas. The government extended the Indradhanu gas grid, connecting to Jorhat and Numaligarh. We are upgrading the Duliajan-Numaligarh pipeline by March 31. We also stopped flaring associated gas; we laid a pipeline from Kumchai (Arunachal) to Kusian (Assam) to evacuate gas. We are augmenting compression for small stranded fields and supplying through virtual pipelines to CGD customers. We have CGD areas in Kapurthala, Kurukshetra, and seven in Arunachal. We also created a natural gas storage facility in depleted fields to store associated gas and repump it.
Rejuvenation of wells is a major project. What does it take, and what is Oil India doing right now? These wells are old, but it is technically possible to find new reserves within them.
Oil India has mastered reservoir management. In mature fields we do workovers using global service providers. We are doing steam injection in Rajasthan at 1,060 m depth—globally this is done at 600-800 m. We also flood carbonated water to enhance hydrocarbon mobility. We are implementing co-mingled production from stacked sand packs, and using plunger lifts and electric heaters for heavy crude.
