As energy demand continues to outpace production, it’s no wonder that India is aggressively pursuing the country’s more than 50 Bbbl and 1.3 Tcm (47 Tcf) of proven oil and gas reserves both onshore and offshore.

Companies such as state-run Oil and Natural Gas Corp. (ONGC) and Gujarat State Petroleum Corp. Ltd. (GSPC) along with Reliance Industries Ltd. and BP are planning to spend billions in offshore hydrocarbon pursuits, tackling deepwater prospects, while others such as Cairn India are tapping EOR technology to improve recovery rates at existing fields onshore.

But there is much ground to cover.

For the most part, India’s sedimentary basins are largely unexplored. Yet not even the government’s launch of a new exploration licensing policy about 15 years ago, which established the auction framework to award licenses under production-sharing contracts, has sparked a worldwide bidding frenzy despite the potential for commercial discoveries.

“Participation by international players remains low, with only 12% of the total acreage and about 7% of total contracts awarded to foreign players to date,” Dilip Khanna, oil and gas partner for EY India, told E&P. “This is due to the following challenges faced in the past few years by international E&P players: comparison of prospects in India relative to other countries, perception of slow and bureaucratic decision-making, and disputes arising between the government and operating companies on matters of cost recovery and obtaining environmental and land clearances from various government departments.”

The drop in crude oil prices could further slow investment from the private sector, while the blow to ONGC and Oil India is softened by the government’s decision to exempt the upstream companies from paying the fuel subsidy with crude prices below $60/bbl.

“The new government in India is [aware] of these issues and is taking positive steps to encourage foreign investments in India’s E&P sector,” Khanna added. “Some significant changes include the new market-linked gas pricing formula currently in force, the new revenue-sharing model for upstream projects being considered, creation of the National Data Repository for all upstream blocks and upcoming bidding rounds for marginal fields and E&P blocks.”

In the meantime, the Indian government pushes a Made in India initiative, which brought together ONGC and Pan-IIT—a research consortium of seven premier Indian Institutes of Technology—in search of technologies to enhance not only hydrocarbons but also alternative energy sources. Research areas identified include geoscience, reservoir characterization, enhanced oil and gas production, and unconventional hydrocarbon exploration as well as software development, engineering solutions and alternate energy resources.

This comes as oil and gas companies advance their E&P plans.

On The Fast Track

ONGC Ltd. is moving ahead to develop the northern part of the KG-DWN-98/2 deepwater block in the Bay of Bengal using a cluster method.

“Considering the vast area for development, ONGC is using [a] cluster approach to bring oil and gas finds in the Block KG-DWN-98/2, or KG-D5, which sits next to Reliance Industries' KG-D6, to production," said Dharmendra Pradhan, India’s petroleum and natural gas minister.

So far, the explorer has made 11 oil and gas discoveries in the KG-DWN-98/2 Block, which spans 7,295 sq km (2,817 sq miles) and is divided into the Northern Discovery Area (NDA) and Southern Discovery Area (SDA).

The company will initially take on the development of 11 fields in the NDA of KG-D5 along with a gas field in the adjacent Block-IG (PEL) under a three-cluster plan, the minister said. The prospects, identified after two exploration phases, are located in water depths ranging from 594 m to 1,283 m (1,949 ft to 4,209 ft).

Pradhan also said the developer is aiming to produce first gas from NDA fields by mid-2018 and first oil by mid-2019.

“Parallel execution of a number of project activities are in progress to ensure fast-track development of these fields,” Pradhan added.

Development of the UD-1 gas discovery in SDA will be taken up in the later stage. “Considering the water depth [2,400 m to 3,200 m, or 7,874 ft to 10,499 ft] and the constrained techno-economic solutions, execution of this [SDA] is presently not being pursued for development,” he said. “Scouting for [a] suitable technology/solution for field development is in progress.”

Closer Look At Clusters

Considering many discoveries in the NDA are not independently viable, ONGC is tying up the prospects in clusters for development. It will develop 11 fields in NDA and one in the adjacent Block IG in three clusters by drilling 43 development and injection wells.

· Cluster 1, a gas cluster, is comprised of the D and E fields of KG-DWN-98/2 and the G-4 Field in the adjacent IG Block. The plan involves drilling eight wells in the G4 Field, two wells in the D Field and one well in the E Field.
The development wells will target hydrocarbon prospects identified after the two-phase exploration work in these three fields. As per the declaration of commerciality (DoC) report, a peak production rate of 14.5 MMcm/d (512 MMcf/d) is expected from this cluster with a 15-year field life.

· Cluster 2A focuses on the A2, G2-P1, M3, M1 and G-2-2 fields in the NDA of KG-D5. The operator plans to drill 14 oil wells and 10 water injectors in this cluster, which is considered be a major oil prospect. According to the DoC, this cluster is expected to produce about 31.5 MMmt of oil in 15 years with a peak production rate of 91,000 bbl/d.

· Cluster 2B, a gas cluster, is a group of four fields—R, U3, U1 and A1—in the NDA. The plan envisages drilling eight free gas wells in these four fields. This cluster is likely to produce 32.5 Bcm (1.1 Tcf) of gas in 14 years with a peak production rate of 12.5 MMcm/d (441 MMcf/d), according to the DoC.

Dynamic modeling results suggest total gas production from gas fields in the NDA along with the G-4 Field of 84.41 Bcm (3 Tcf) with a peak gas rate of 33 MMcm/d (1.2 Bcf/d) over a period of 15 years.

The NDA is estimated to have reserves of 121 million tons of oil in place and 78 Bcm (2.8 Tcf) of initial gas in place, while the SDA holds 80.9 Bcm (2.9 Tcf) of initial gas in place. Based on the geological and geophysical analysis, the KG-D5 Block holds substantial upside potential of about 265 MMmt.

ONGC is looking at hiring the spare gas transportation facilities of the adjacent KG-OSN-2001/3 Block being developed by GSPC to bring the production from Cluster-I. The cluster’s three fields are near the 23-km (14-mile), 20-in. subsea pipeline planned by GSPC to transport oil and gas from its Deen Dayal Field in KG-OSN-2001/3 to an onshore terminal at Mallavaram on Andhra coast.

Production from Cluster-2A and 2B, however, will be transported through facilities that ONGC plans to develop. The targeted 90,000 bbl/d of oil from Cluster-2A will be transported to an FPSO vessel, and 12.5 MMcm/d of gas from Cluster-2B will be piped to an onshore terminal at Odalarevu on Andhra coast via a subsea pipeline. ONGC has awarded Technip a contract to develop the onshore terminal at Odalarevu to source oil and gas from KG-D5 and the neighboring shallow-water VA and S1 fields.

Offshore Push Grows

With 56% of India’s proven reserves in offshore basins, Khanna said that Indian companies have made substantial investments offshore, pointing out gas exploration in proven Mumbai Offshore and Krishna Godavari (KG) offshore basins.

“ONGC announced plans to invest about $1 billion by 2017 in the redevelopment of Mumbai High, an offshore oil and gas field on the West Coast. Further, RIL-BP, ONGC and GSPC are slated to make major investments (more than $5 billion) in the next three years in the KG Basin,” Khanna added. “Given the proven prospectivity of these regions, investments and further exploration are expected to continue at a steady rate.”

The government also is encouraging investment in the offshore Cauvery, Mahanadi and Kerela-Konkan basins, Khanna continued, noting “prospectivity has been identified in these regions; however, foreign and private investment are required to drive further exploration and proving up of reserves.”

ONGC and GSPC aren’t the only ones making strides offshore.

Cairn India Ltd. highlighted offshore production growth Jan. 22, 2015, during a conference call on the third-quarter financial results for the period ended Dec. 31, 2014. The company said it posted a 24% sequential production growth, reaching 39,000 boe/d. Building on the success of finds in the Ravva Basin, quarter notables also included a new discovery in Block RE-6 that is estimated to have between 10 MMbbl and 15 MMbbl of hydrocarbons in place. The company aims to produce about 4,000 boe/d.

“Ravva continues to be an excellent example of good reservoir management too, with a world-class recovery rate of 48% achieved this quarter. Gross daily production of about 28,000 barrels equivalent in the third quarter has been aided by eight infill wells drilled this fiscal [quarter],” Cairn CEO Mayank Ashar said in Cairn’s online transcript of the call.

In addition, optimization initiatives in Cambay helped lead to production growth of 10% year-on-year on a nine-month basis.

“Gross daily production of over 11,000 barrels equivalent was higher this quarter largely on account of successful ramp-up post well surveys. For the next quarter, a coil tubing campaign has been planned,” Ashar said. “This could impact volumes in the period but would aid production growth in subsequent quarters. Our recent success in Ravva and Cambay both point toward our constant endeavor to maximize value for shareholders through continued efforts.”

EOR Efforts Continue

While developments move forward offshore, operators also are progressing with the development of onshore fields. Cairn said it continues to focus on its core Mangala, Bhagyam and Aishwariya (MBA) reservoirs, which have 2.2 Bbbl of discovered hydrocarbons in place, concentrating on “infrastructure creation and prudent reservoir management in both waterflood and EOR implementation.”

“Over 90% of our production volumes are from core fields of MBA, Ravva and Cambay. These fields are resilient to volatility in oil prices due to their low operating cost and high margin,” Ashar said. “In addition, we have a rich set of optionalities for growth in the areas of exploration, satellite fields, Barmer Hill and the gas business.”

Ashar later spoke of the combination of good geology, technology adoption skills and growth options that uniquely position the company. The Mangala EOR project is among the examples of how the company is using technology to grow production. At the end of October 2014, Cairn marked the tie-up of three major projects—the first polymer injection at Mangala, which the company said is one of the largest polymer floods in the world.

“The Mangala EOR full ramp-up is progressing well; the commissioning of critical packages is in advanced stages of completion. High-performance rigs continue to drill additional EOR wells,” the company said in a statement. “After positive water cut and oil trends observed in the Mangala ASP pilot, we have progressed to testing of potential oilfield chemicals. We would be concluding the pilot within fourth-quarter fiscal year 2015 as planned.

“First injection of polymer at the field and full field ramp-up is underway to enhance recovery rates by 7% to 10%,” the company added. “We expect it would take about six months for the production to see the impact.”

The Mangala EOR project is one of several in which Cairn is using technology to improve its understanding of geology and improve capital efficiency as the industry continues to endure a downturn marked by low oil prices, too much supply and too little demand.

Reflecting on previous downturns and companies’ resilience in capital allocation, cost control and using employees’ creative capability, Ashar said, “My learning has been that there are always opportunities for good companies with good assets, and Cairn is no different.”

Ravi Prasad is an India-based contributor to E&P. Velda Addison is the associate online editor for E&P.