U.S. Department of the Interior

U.S. Geological Survey

Fact Sheet 2013–3113

April 2014

World Petroleum Resources Project

Assessment of Potential Shale Oil and Tight Sandstone Gas 

Resources of the Assam, Bombay, Cauvery, and Krishna-Godavari 

Provinces, India, 2013

60° 65° 70° 75° 80° 85° 90° 95° 100°

35°

30°

25°

20°

15°

10°

5°

BOMBAY

PROVINCE

(8043)

CAUVERY

PROVINCE (8044)

INDIA

PAKISTAN

AFGHANISTAN

NEPAL

BANGLADESH

BURMA

CHINA

Cambay Shale Oil AU

(80430262)

Komarakshi Shale Oil AU

(80440163)

Sattapadi-Andimadam Shale Oil AU

(80440162)

Raghavapuram Shale Oil AU

(80450162)

Paleocene Palakollu Shale Oil AU

(80450163)

Eocene Vadaparru Shale Oil AU

(80450164)

Kopili Shale Oil AU

(80340161)

A

60° 65° 70° 75° 80° 85° 90° 95° 100°

35°

30°

25°

20°

15°

10°

5°

BOMBAY

PROVINCE

(8043)

ASSAM

PROVINCE

(8034)

CAUVERY

PROVINCE (8044)

INDIA

PAKISTAN

AFGHANISTAN

NEPAL

BANGLADESH

BURMA

CHINA

BHUTAN

Olpad Formation

Tight Sandstone Gas AU

(80430263)

Kommugudem Formation

Tight Sandstone Gas AU

(80450261)

Barail Coal Shale

Tight Sandstone Gas AU

(80340162)

SRI

LANKA

B

0 500 1,000 KILOMETERS

0 250 500 MILES

0 500 1,000 KILOMETERS

0 250 500 MILES

SRI

LANKA

BHUTAN

ASSAM

PROVINCE

(8034)

KRISHNA-GODAVARI

PROVINCE

(8045)

KRISHNA-GODAVARI

PROVINCE

(8045)

Introduction

The U.S. Geological Survey (USGS), 

in cooperation with the U.S. Department of 

State, is assessing the potential for unconventional oil and gas resources (shale gas, 

shale oil, tight sandstone gas, and coalbed 

gas) in priority geologic provinces worldwide. This report summarizes the geologic 

models and assessment of potential shale 

oil and tight sandstone gas resources 

of geologic provinces in India. Assam, 

Bombay, Cauvery, and Krishna-Godavari 

Provinces, and the unconventional reservoirs they contain, are located along the 

margins of the Indian subcontinent (fig. 1A

and B). Figure 1A and B show the locations 

Using a well performance-based 

geologic assessment methodology, the 

U.S. Geological Survey estimated a 

technically recoverable mean volume 

of 62 million barrels of oil in shale oil 

reservoirs, and more than 3,700 billion 

cubic feet of gas in tight sandstone gas 

reservoirs in the Bombay and KrishnaGodavari Provinces of India.*1

 Shale oil 

and tight sandstone gas reservoirs were 

evaluated in the Assam and Cauvery 

Provinces, but these reservoirs were not 

quantitatively assessed.

*The term “provinces” refer to geologically 

defined units assessed by the USGS for the 

purposes of this report and carries no political or 

diplomatic connotation.

Figure 1. Location of the Assam, Bombay, 

Cauvery, and Krishna-Godavari Provinces in India 

(orange). A, areas of the shale oil assessment 

units (AU) that were assessed (solid green area) 

and evaluated, but not assessed (blue outlines) 

in this study. B, areas of the tight sandstone 

gas assessment units (AU) that were assessed 

(solid red areas) and evaluated, but not assessed 

(blue outlines) in this study. Maps of AUs were 

based on data from the Directorate General of 

Hydrocarbons (written commun., 2009).
of assessed and unassessed shale oil and tight sandstone gas 

assessment units (AUs), respectively. Unconventional reservoirs 

in the Ganga Basin and the Damodar Valley area within the 

Gondwana basins (not shown on fig. 1) were considered, but not 

evaluated in the study because of insufficient data.

Reservoirs with the greatest potential for containing undiscovered oil and gas resources were assessed. Geologic criteria 

were developed to evaluate shale oil and tight sandstone gas 

reservoirs including: (1) average total organic carbon (TOC) 

content 2.0 weight percent or more; (2) presence of Type I, II, 

or IIS as the main kerogen type within the source rock for shale 

oil, and Type III (coal) for tight sandstone gas; (3) net thickness of organic-rich intervals 15 meters or more; (4) adequate 

thermal maturity for oil and gas generation; (5) presence of 

abnormally pressured reservoirs; and (6) evidence of oil or gas 

storage capacity in the rocks. All of these criteria must be present at one place to continue with an assessment (Charpentier 

and Cook, 2011).

For each of the assessed provinces, variations in the 

organic-rich shales, types of kerogen, storage potential, and 

thermal maturity for oil and gas generation are subject to 

significant geologic uncertainty. Consequently, unconventional 

accumulations in the United States were used as geologic and 

engineering analogs to assess these provinces (Charpentier and 

Cook, 2011). Analog data from United States accumulations 

included estimated ultimate recoveries from wells, average 

drainage areas of wells, and well exploration success ratios. Key 

assessment input data are listed in table 1.

Geologic Models for Assessment

Assam Province (Assam-Arakan Basin)

This province is interpreted to have originated as a Mesozoic (Early Cretaceous) rifted passive margin, but evolved into 

a foreland basin with fold and thrust belts during the Neogene 

when the Indian plate collided with the Eurasian continent. The 

Eocene Kopili Shale was evaluated for shale oil and the Oligocene Barail Coal Shale was evaluated for tight sandstone gas.

The Kopili Shale was deposited in a proximal marine shelf 

environment. The Kopili Shale and the underlying Sylhet Formation grade laterally into distal marine mudstones and merge 

below thrust sheets to form the Disang Group. Thrust sheet 

loading might have sufficiently buried the Disang Group to generate oil and gas. These rocks are considered the main source 

for oil and gas in conventional accumulations in the province. 

The extent of the Kopili Shale and retention of hydrocarbons are 

unknown beneath thrust sheets. This reservoir was not quantitatively assessed because of the significant geologic uncertainty.

The Barail Coal Shale was deposited 

in a paralic (marginal marine) and nearshore 

environment and consists of mudstones, 

carbonaceous mudstones, sandstones, and 

coal. The geologic extent, depositional facies, 

and presence of hydrocarbons beneath thrust 

sheets are unknown. This reservoir was not 

quantitatively assessed because of the significant geologic uncertainty.

Bombay Province (Cambay Basin)

The Cambay Basin began as a failed 

rift in the Late Cretaceous during which time 

a delta developed and extended southwestward toward the Bombay Shelf. The upper 

Paleocene to middle Eocene Cambay Shale 

was evaluated for shale oil, and the Paleocene Olpad Formation was evaluated for 

tight sandstone gas.

The Cambay Shale was deposited in 

deltaic and nearshore marine environments 

in the northern and central parts of the basin, 

and in more distal marine environments in 

the southern part of the basin. The formation consists of marine mudstone with some 

interbedded siltstone and sandstone intervals, coal, and carbonaceous mudstone. The 

distal marine Cambay Shale in the southern 

depocenter was quantitatively assessed, but 

a probability that sufficient oil resources 

might not be present was estimated. A possibility exists that the oil in conventional 

Potential production area of AU (acres) 262,500 394,000 525,000 393,833

Average drainage area of wells (acres) 200 250 350 267

Average EUR (MMBO) 0.04 0.07 0.25 0.08

Future success ratio (percent) 50 65 85 67

Potential production area of AU (acres) 550,000 1,156,000 1,270,000 992,000

Average drainage area of wells (acres) 100 120 200 140

Average EUR (BCFG) 0.2 0.6 1.4 0.64

Future success ratio (percent) 25 50 80 52

Potential production area of AU (acres) 200,000 800,000 1,343,000 781,000

Average drainage area of wells (acres) 100 120 200 140

Average EUR (BCFG) 0.2 0.6 1.4 0.64

Future success ratio (percent) 25 50 80 52

Assessment input data

Assessment input data

Assessment input data Kommugudem Formation Tight Sandstone Gas AU

Olpad Formation Tight Sandstone Gas AU

Cambay Shale Oil AU

Minimum Mode/Median Maximum Calculated mean

Minimum Mode/Median Maximum Calculated mean

Minimum Mode/Median Maximum Calculated mean

Table 1. Key assessment data for shale oil and tight sandstone gas assessment units 

in India. Average estimated ultimate recovery (EUR) per well, average drainage area, 

and future success ratios are from United States analogs. Areas of AUs were calculated 

from maps and data provided by the India Directorate General of Hydrocarbons (written 

commun., 2009).

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; AU, assessment unit. Central tendencies are 

modes except for average EUR, which is median]
reservoirs in the Cambay Basin may have migrated a long 

distance from source rocks farther to the south.

The Olpad Formation was deposited in lacustrine, deltaic, 

and (or) nearshore marine environments in the northern and 

central parts of the basin. The extents of the Olpad Formation 

source rocks in the southern and deeper portions of the basin are 

unknown. The Olpad Formation consists of syn-rift, volcanogenic 

conglomerates, rock wash (trap wash), sandstones, siltstones, 

mudstones, claystones, coals, and carbonaceous mudstones. The 

Olpad Formation was also quantitatively assessed, but has an 

estimated probability that the sandstone may actually be a conventional reservoir rather than a tight sandstone reservoir.

Cauvery Province (Cauvery Basin)

This province is a rifted passive margin originating during 

the Late Jurassic through Early Cretaceous when the India and 

Sri Lanka landmass separated from Gondwana. The combined 

Jurassic to Lower Cretaceous Andimadam Formation and Lower 

to Upper Cretaceous Sattapadi Shale, and the Upper Cretaceous 

Komarakshi Formation were evaluated for shale oil.

The Andimadam Formation and Sattapadi Shale were both 

deposited in marine environments, but the lowermost Andimadam section may contain lacustrine mudstones. The two formations are treated as a single assessment unit in this study because 

the mudstones in the stratigraphic succession are not easily differentiated. The main kerogen type in the mudstones is Type III and 

a low probability exists for the presence of shale oil reservoirs. 

These formations were not quantitatively assessed.

The Komarakshi Formation (includes the Kudavasal and 

Portonovo mudstones) was deposited in a nearshore marine 

environment. The main kerogen type in these mudstones is 

Type III and a low probability exists for the presence of shaleoil reservoirs. This formation was not quantitatively assessed.

Krishna-Godavari Province (Krishna-Godavari Basin)

This province is a rifted, passive margin originating 

during the late Paleozoic through Early Cretaceous when the 

India landmass separated from Gondwana. The Cretaceous 

Raghavapuram Shale, Paleocene Palakollu Shale, and Eocene 

Vadaparru Shale were evaluated for shale oil. The Permian 

Kommugudem Formation was evaluated for tight sandstone gas.

The Raghavapuram Shale, Palakollu Shale, and Vadaparru 

Shale were deposited in marginal marine and shelf environments. The main kerogen type in these mudstones is Type III 

and a low probability exists for the presence of shale-oil 

reservoirs. These formations were not quantitatively assessed.

The Kommugudem Formation consists of alternating 

sandstone and mudstone with coal beds. It was deposited in 

lagoonal, fluvial, and deltaic environments. Gas is produced 

from the Kommugudem Formation in the northern onshore part 

of the Krishna-Godavari Basin. The reservoir might actually 

be a conventional reservoir based on gas production within the 

conventional Mandapeta gas field. The Kommugudem Formation was quantitatively assessed, but a low probability exists 

for the presence of tight sandstone gas reservoirs because the 

sandstone might not be classified as tight.

Resource Summary

Only the Cambay Shale, Olpad Formation, and Kommugudem Formation were quantitatively assessed. The assessment units are Cambay Shale Oil, Olpad Formation Tight 

Sandstone Gas, and Kommugudem Formation Tight Sandstone 

Gas (table 2).

The results of the USGS assessment of shale oil and tight 

sandstone gas resources in the Assam, Bombay, Cauvery, 

and Krishna-Godavari Provinces in India are listed in table 

2. In summary, the estimated mean volumes of technically 

recoverable petroleum resources are as follows: (1) Cambay 

Shale Oil AU of the Bombay Province, with an AU probability of 0.8–62 million barrels of oil (MMBO; range, 0 to 

135 MMBO); 169 billion cubic feet of natural gas (BCFG; 

range, 0 to 365 BCFG); and 6 MMB of natural gas liquids 

(MMBNGL; range, 0 to 12 MMBNGL); (2) Olpad Formation Tight Sandstone Gas AU in the Bombay Province, with 

an AU probability of 0.9–2,101 BCFG (range, 0 to 3,970 

BCFG) and 21 MMBNGL (range, 0 to 43 MMBNGL); and 

(3) Kommugudem Formation Tight Sandstone Gas AU of 

the Krishna-Godavari Province, with an AU probability of 

0.9–1,653 BCFG (range, 0 to 3,399 BCFG) and 20 MMBNGL 

(range, 0 to 43 MMBNGL). The ranges of resource estimates 

for these unconventional resources reflect the considerable 

geologic uncertainty in these AUs.

Assessment units for Kopili Shale Oil, Barail Coal Shale 

Tight Sandstone Gas, Sattapadi-Andimadam Shale Oil, Komarakshi Shale Oil, Raghavapuram Shale Oil, Paleocene Palakollu 

Shale Oil, and Eocene Vadaparru Shale Oil were identified 

(table 2), but not quantitatively assessed because of the significant geologic uncertainty.

Acknowledgments

The authors are grateful for the data and consultation from 

the India Ministry of Petroleum and Natural Gas and its agencies. The India Directorate General of Hydrocarbons (DGH) 

provided much of the data used in this study. Valuable data and 

contributions were also provided by Oil India, Limited (OIL); 

Gas Authority of India, Limited (GAIL); and Oil and Natural 

Gas Corporation (ONGC).

We thank Mr. Chandra Bhan Singh, Indian Ministry of 

Petroleum and Natural Gas, and Mr. S.K. Srivastava, Director General of the Directorate General of Hydrocarbons 

(DGH). Mr. Sanjay Chawla, Head, Alternate Energy; Mr. 

Atanu Banerjee, Geologist; Mr. S.C. Sarma, Head, Shale Gas 

Programme; and Mr. Malcom Lall, National and International 

Cooperation and Technical Coordinator, DGH, were particularly helpful by sharing information and insights that gave 

a better understanding of the petroleum geology and unconventional oil and gas resource potential of the basins in India 

prior to the USGS assessment.

The authors are grateful for the coordination and logistical 

help provided by the U.S. Department of State, particularly Mr. 

Joseph Figueiredo, Ms. Chung Joon Lee, Ms. Angie Mizeur, 

Mr. David S. Williams, and Mr. Jason A. Donovan.
ISSN 2327-6916 (print)

ISSN 2327-6932 (online)

http://dx.doi.org/10.3133/fs20133113

Reference

Charpentier, R.R., and Cook, T.A., 2011, USGS 

methodology for assessing continuous petroleum 

resources: U.S. Geological Survey Open–File 

Report 2011–1167, 73 p.

Krishna-Godavari Province, Mesozoic-Cenozoic Composite TPS, 804501

Kopili Shale Oil AU, 80340161

Assam Province, Cenozoic Composite TPS, 803401

Barail Coal Shale Tight Sandstone

Gas AU, 80340162

Not quantitatively assessed

Not quantitatively assessed

Sattapadi-Andimadam Shale Oil AU,

80440162

Cauvery Province, Mesozoic-Cenozoic Composite TPS, 804401

Komarakshi Shale Oil AU, 80440163

Not quantitatively assessed

Not quantitatively assessed

Raghavapuram Shale Oil AU,

80450162

Paleocene Palakollu Shale Oil AU,

80450163

Not quantitatively assessed

Not quantitatively assessed

Eocene Vadaparru Shale Oil AU,

80450164 Not quantitatively assessed

Cambay Shale Oil AU, 80430262 Oil

Bombay Province, Cenozoic Composite TPS, 804302

0 170 365 169 0 6 12 6

Gas Olpad Formation Tight Sandstone

Gas AU, 80430263 0 2,067 3,970 2,101 0 20 43 21

0.8

0.9

0 63 135 62

Total shale oil resources 169 6

Gas Kommugudem Formation Tight

Sandstone Gas AU, 80450261 0 1,573 3,399 1,653 0 18 43 20

Krishna-Godavari Province, Paleozoic Composite TPS, 804502

0.9

Total tight sandstone gas resources 3,754 41

62

Total undiscovered resources Geologic provinces, total petroleum

systems (TPS), and assessment

units (AU)

Field

type

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

AU

probability

Table 2. Assessment results for potential shale oil and tight sandstone gas resources in India (technically recoverable, 

unconventional resources).

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids. Results shown are fully risked estimates. 

For gas fields, all liquids are included under the natural gas liquids (NGL) category. F95 denotes a 95-percent chance of at least the amount tabulated, F50 

denotes a 50-percent chance, and F5 denotes a 5-percent chance. TPS, total petroleum system; AU, assessment unit. Gray shading indicates not applicable]

For Further Information

Supporting geologic studies of total petroleum systems and assessment units, and reports on the methodology 

used in the assessment of the Assam, Bombay, Cauvery, 

and Krishna-Godavari Provinces, are in progress. Assessment results are available at the USGS Energy Resources 

Program Web site: http://energy.usgs.gov/OilGas/

AssessmentsData/WorldPetroleumAssessment.aspx.

Indian Provinces Assessment Team

Timothy R. Klett, Christopher J. Schenk, Craig J. Wandrey, 

Michael E. Brownfield, Ronald R. Charpentier, 

Marilyn E. Tennyson, and Donald L. Gautier.