India Oil And Gas Upstream Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

India Oil And Gas Upstream Market Trends and Insights

Declining Domestic Output Spurring EOR Investments

National oil output fell from 36 million tonnes in FY2017 to 29.4 million tonnes in FY2024, creating a clear incentive for operators to deploy ASP, polymer, and miscible-gas flooding in mature reservoirs. Cairn Oil & Gas has earmarked USD 1 billion to retrofit its Rajasthan fields with full-field ASP, targeting a 15-20% uplift in recovery factors as per its April 2025 shareholder presentation.^{[1]Vedanta Ltd., “Cairn Rajasthan Renewal Plan Investor Presentation,” vedanta.com} Pilot programs in Assam’s Lakwa and Gujarat’s Kalol fields recorded incremental gains of 4,000–6,000 barrels per day, demonstrating replicable gains across India’s 430 mature fields. Operators now view EOR as a margin-accretive alternative to risky frontier exploration because most surface facilities are already in place, shortening payback periods to under four years.

Expansion of OALP Bid Rounds & HELP Incentives

The Hydrocarbon Exploration & Licensing Policy (HELP) has transitioned India from a cost-recovery production-sharing regime to a transparent revenue-sharing system, thereby eliminating audit disputes while granting full marketing freedom for gas. Since 2018, nine OALP rounds have cumulatively awarded 134 blocks and attracted work-program commitments worth USD 1.37 billion, according to the Directorate General of Hydrocarbons. Major industry players, such as BP and Eni, have pre-qualified for the upcoming Round X, enticed by unified license terms that cover both conventional and unconventional resources. The open-acreage model allows bidders to carve out prospect-specific polygons instead of waiting for government-curated bid maps, thereby accelerating acreage acquisition cycles.

Gas-Price Indexation Reforms Improving Project Economics

In April 2024, the Ministry of Petroleum & Natural Gas shifted new gas production to a dynamic ceiling price linked to 10% of the average Brent crude quotation, replacing the earlier formula pegged to bygone Henry Hub averages. The new index delivers USD 8–9 per MMBtu breakevens for deepwater fields, a level sufficient to sanction KG-Basin satellites and Mahanadi Basin cluster developments. Parallel reforms introduced the Indian Gas Exchange as a trading hub, providing producers with optionality between spot and term sales and enabling downstream buyers to hedge fuel costs. The policy enhances the value proposition of gas-rich acreage awarded under HELP and anchors long-term demand from city-gas distribution projects.

Digital-Oilfield Adoption Led by Indian IT Majors

Infosys and Tata Consultancy Services now bundle data analytics suites, IoT sensor grids, and edge-computing gateways into off-the-shelf “platforms for petroleum,” slashing implementation costs by up to 40% compared with global service companies, according to ONGC’s digital roadmap submission to the Oil Industry Safety Directorate.^{[2]Oil Industry Safety Directorate, “Digital Roadmap for Upstream Operations,” oisd.gov.in} Cairn’s remote operation center in Gurugram streams 34,000 real-time parameters from its Rajasthan and Cambay assets, resulting in a 5% production increase and a 12% operating expenditure reduction within the first year of deployment. Oil India’s DRIVE initiative extends digitalization to HSE compliance and supply-chain inventory, aiming to achieve USD 60 million in annual savings by 2027.

Geological Complexity of Mature Onshore Basins

Reservoir heterogeneity in Rajasthan’s Barmer-Hill and Assam’s fractured carbonates requires multi-stage hydraulic fracturing and high-density vertical logging, which doubles drilling costs compared to vintage wells. The Directorate General of Hydrocarbons lists more than 60 prospects with permeability below 1 mD, classifying them as tight oil. Reservoir-quality uncertainty elevates failure risk and forces operators to pre-commit completion hardware while drilling, tying up capital and inflating field-level break-evens. Water sourcing for frac jobs also raises environmental scrutiny in arid districts such as Jaisalmer.

Prolonged Environmental & Land-Acquisition Approvals

Forest clearances can extend beyond 900 days for upstream locations that intersect wildlife corridors, according to the Ministry of Environment, Forest & Climate Change’s April 2025 compliance dashboard.^{[3]Ministry of Environment, Forest & Climate Change, “Environment Clearance Dashboard Q1 2025,” moefcc.gov.in} Parallel land-acquisition legislation mandates extensive community consultation, leading to compensation packages that can add 8–12% to overall project budgets. The elongated timelines deter foreign independents from frontier plays and skew capital toward brownfield re-development, where statutory paperwork already exists.

Segment Analysis

By Location of Deployment: Offshore Acceleration Drives Future Growth

Offshore fields delivered 45.5% of 2024 revenue, yet they are set to outpace onshore operations with a 6.5% CAGR through 2030 as deepwater tie-backs shorten payback periods. The India oil & gas upstream market size derived from offshore alone is projected to grow from USD 6.94 billion in 2024 to USD 9.57 billion by 2030. Meanwhile, the onshore domain, although still larger, faces a plateauing output at a 3.7% CAGR because most low-hanging resources have already been drained.

The offshore growth narrative is based on ONGC’s KG-DWN-98/2 cluster, Reliance-BP’s MJ and Satellite developments, and the collaboration between Oil India and Petrobras in the Mahanadi Basin. Sub-sea boosting, multiphase pumping, and long-tie-back pipelines reduce unit lifting costs, even in water depths exceeding 1,500 meters. Decommissioning of the Panna-Mukta-Tapti platforms also demonstrates the regulator’s capacity to manage late-life liabilities, encouraging new entrants wary of end-of-life obligations. Onshore opportunities remain attractive where mature infrastructure exists; however, stringent water-use restrictions and land-access delays can dilute near-term growth.

Note: Segment shares of all individual segments available upon report purchase

By Resource Type: Natural Gas Momentum Builds on Policy Support

Crude oil retained a 68.2% revenue share in 2024; however, natural-gas-linked revenue is expected to capture 34% by 2030 as gas output increases to meet the national goal of a 15% primary-energy share. Gas-rich blocks licensed under HELP contribute to an India oil & gas upstream market size of USD 5.63 billion in 2024 for gas, expanding at a 7.1% CAGR. This acceleration outpaces oil, which grows at 4.3%, mirroring policy incentives and lower carbon intensity.

Enabling infrastructure—including the National Gas Grid extension and 295 new CNG stations—creates offtake certainty. Gas producers enjoy marketing freedom for volumes up to 6 Tcf discovered post-2016, shielding returns from legacy price caps. Conversely, oil-focused assets rely on EOR spending to stem declines, adding cost layers that curb margin upside. Associated-gas monetization remains an under-exploited lever; ONGC’s Mumbai High flare-back project alone could contribute 0.4 Bcf/d once completed, reinforcing balanced oil-gas portfolios.

By Well Type: Conventional Dominance Faces Unconventional Challenge

Conventional wells represented 82.8% of India's oil & gas upstream market share in 2024. However, unconventional drilling—tight oil, shale gas, and coal-bed methane—posts a 6.3% CAGR, positioning it to reach USD 4.45 billion by 2030. Multistage fracturing in the Cambay Shale and directional drilling in the Raniganj coal seams have pushed unconventional deliverability to 3.5 Bcf/d in pilot tests.

The Directorate General of Hydrocarbons issued detailed guidelines in December 2024, covering well control, frac-water disposal, and produced-water reinjection, providing regulatory certainty that unlocks capital. Still, proppant supply currently meets only 30% of projected demand, prompting the development of new ceramic-proppant plants under the Production Linked Incentive scheme. Conventional wells continue to bankroll corporate cash flows, but declining discovery sizes underscore the urgency of diversifying into unconventional domains.

Note: Segment shares of all individual segments available upon report purchase

By Service: Decommissioning Emerges as Growth Driver

Development and production (D&P) accounted for a 65.0% share of total spending in 2024. Yet, decommissioning registers the fastest 6.9% CAGR, expanding its revenue pool from USD 0.68 billion in 2024 to USD 1.02 billion by 2030. The Tapti and Panna-Mukta-Tapti platform removals validated local contractors’ ability to execute complex lift operations, a prerequisite for the 78 offshore structures scheduled for retirement by 2030.

Larsen & Toubro’s “plug-and-abandon” spread and Cochin Shipyard’s new recycling dock give India the capacity to meet IMO and EU waste-management standards. D&P activity remains buoyant due to EOR and infill drilling, but the decommissioning backlog provides long-cycle visibility and a hedge against drilling down-cycles. Exploration services lag because operators prioritize the monetization of proven reserves over frontier risk.

Geography Analysis

Western Offshore, anchored by Mumbai High and Heera clusters, delivered roughly 49% of national liquids in 2024 and maintains a 3.8% CAGR, benefiting from subsea electrical-submersible-pump (ESP) retrofits that trim water cut and extend plateau life. The eastern seaboard gains momentum as KG-D6’s new MJ field reaches 15 MMscmd plateau in 2025, lifting regional gas to 24% of national output. Northeast India’s oil production, primarily from Assam, is expected to see an 8.4% CAGR as infill drilling and polymer flooding rejuvenate aging fields on 7,650 km² of new acreage granted to Vedanta.

Rajasthan remains critical, accounting for 25% of total liquids and targeting a 50% share by 2030 under Cairn’s Rajasthan Renewal Plan. The basin’s low-sulfur crude fetches a premium in domestic refineries, enhancing project economics even at higher water-handling costs. Gujarat’s Cambay Basin, although mature, leverages its proximity to Jamnagar and Vadodara petrochemical hubs, sustaining steady demand and minimizing logistics expenses.

Frontier areas, such as the Andaman deepwater and Kutch-Saurashtra basin, attract early-stage seismic programs financed through the National Seismic Program, which is expected to complete 48,000 line-kilometers by 2024. These high-risk, high-reward plays could transform regional dynamics if commercial hydrocarbons are proven; however, logistical challenges and cyclone exposure prolong the appraisal process.

Infrastructure disparities shape resource monetization; the North-East Grid and Haldia–Jagdishpur spur enable gas evacuation, whereas inadequate port depth at Paradip constrains large-diameter rig imports. Such gaps direct capital toward basins with complete midstream value chains, reinforcing established centers while policy incentives attempt to redistribute investment geographically.