We have no
alternative but to
develop Shale Gas
resources of the
Country
As per earlier figures compiled in
DGH the production of
Conventional Gas in India is
likely to decline after 2015.
Therefore, Shale Gas will be the
only Domestic Source of Gas
availabile in India, in the near
future.
India’s conventional supplies decline after 2015
Million Cubic Feet per Day (MMCF/Day)
CONVENTIONAL GAS SUPPLY IN INDIA
9,000
8,000
7,000
6,000
Oil India
5,000
Private & JVs
4,000
3,000
2,000
ONGC
1,000
0
200708
Source: DGH
200809
200910
201011
201112
201213
201314
201415
201516
201617
201718
201819
201920
202021
• As per working group of Petroleum & Natural Gas
(2012-17) the Domestic Gas Production during the
period 2016-17 to 2021-22 will not increase
significantly.
• The demand for gas in the country will be met by
import of LNG to the tune of 101 MMSCMD i.e.
40% of then demand in 2013-14 and will increase
to 163 MMSCMD i.e. 45% of then demand
expected in 2016-17. Thereafter, the country may
import both LNG and cross-country piped gas to
the tune of 288 MMSCMD or 57% of then demand
in 2017-18 to 2021-22.
• This is a very serious situation as during the
period 2025-2030 the import of Crude Oil may
reach 90% and import of Natural Gas can be over
60%.
600
504
474
500
400
300
200
100
244
197
124
279
250
149
302
271
170
356
333
177
510
480
517
487
524
494
531 Pipeline import
501
394
373
LNG Import
216
210
222
229
236
243
Domestic
Gas
0
2012-13 2013-14 2014-15 2015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22
Availaibility of Gas (Domestic & Imported)
Demand for Natural Gas
Pipeline import
LNG Import
Domestic Gas
Price -
Price
Price
USD 12-14
USD 14-18
USD 4.2-6.5
MMBTU
MMBTU
MMBTU
Domestic Gas Production
Based on IEA’s World Energy Outlook
2009 India’s incremental Carbon Footprint
between the period 2007-2030 will be 2035
MT Co2 /Annum. Incidentally, this + 153%
increase over 2007 will be the highest for
any major country in the world. In contrast,
the figures for USA, Europeon Union and
Japan are respectively -4%, -10% and 20%. As we produce more gas in the
country, the Carbon Footprint will
dramatically improve.
India needs to manage its carbon footprint
INCREMENTAL CARBON FOOTPRINT 20072030*
(MT CO2/ ANNUM)
Increase over
2007, %
China
5,544
India
2,035
Russia
354
91%
China
153%
Russia
22%
India
US
US
-207
-4%
Japan
-248
-20%
European
-370
Union
PER CAPITA INCREMENTAL CARBON
FOOTPRINT 2007 – 2030*
(MT CO2/ ANNUM/ MILLION PEOPLE)
-10%
European
Union
4
2
2
-1
-1
Japan -2
*Based on IEA’s World Energy Outlook 2009 - Reference Scenario, which provides a baseline picture of how global energy markets would evolve if
governments make no changes to their existing policies and measures
Source: IEA, European Union, www.worldatlas.com
As per IEA’s World Energy Outlook 2009,
India’s Oil & Gas import by 2030 would
be over 300 billion USD in 2009 terms.
In addition, about 70 billion USD may be
used to import LNG and piped gas from
abroad. India will be only major country
in the world investing 6.5% of its GDP on
Oil & Gas imports. Figures for China,
Japan and European Union the other
major importing regions would be
respectively only 3.5%, 3% and 2.5%.
EXPENDITURE ON NET O&G IMPORTS* AS A % OF GDP
Percentage of GDP
EXPENDITURE* ON NET O&G IMPORTS
US$ Billion
?
Indian economy and foreign
exchange reserves cannot
sustain the projected, future
energy imports. Therefore,
early
development
of
Domestic Shale Gas/Oil is
essential.
What is shale gas development?
It requires large dispersed and dynamic above ground activity
Shale characterization
A land seismic truck
Core logging
Exploration
Stratigraphic imaging
Development
Large land requirement
Production
Surface facilities
Multi horizontal wells & PAD drilling
Waste processing
Multi truck and frac equipment
Pipeline transportation
Basic technology for shale gas development
Shale Gas approach
Multi stage fraccing:
5-20 fraccs per well
Typical use 4 Mn Gallons
water/well
Typical proppant 10003000 metric tonnes
Source: Horizontal Wells and Gas Shales (The Oil Drum , 2009); Horizontal Well technology (Dr. S.D. Joshi), EIA
Unlocking the
potential of Shale
Gas
in India
Cambay Basin
Gondwana
Basin
Assam-Arakan
Basin
KrishnaGodavari Basin
Cauvery Basin
Vindhyan Basin
Bengal Basin
Rajasthan Basin
Shale Gas Resource of India by ARI, 2011
Indicative resources of Non Conventional Natural Gases as
broadly estimated by the Author
Cam- KG Cauver Assam - Vindhybay
y
Arakan an
Indicative
Not
resource.
45
49 9
10
Known
Risked
Tight
Recoverable Sand
(Tcf)
40
85
49 9
10 (?)
Total
Grand Total say 200 Tcf
Gondwana
20
CBM
30
50
Generalised Stratigraphy of Cambay Basin
Organic Content of Cambay Shale
Tight sand reservoirs in Cambay Basin
Source Oilex Ltd
CAMBAY PROJECT- HYDROCARBONS-IN-PLACE IN TIGHT
SANDSTONE
NSAI’s Assessment of Hydrocabons In-Place
Zone
X
Y
Total-Gross
Zone
Z
180-200
200-300
300-400
Total-Gross
Discovered In-Place Volume Estimate
Oil MMbbl
Gas BCF
667
965
1,633
654
660
1314
Undiscovered In-Place Volume Estimate
Oil MMbbl
Gas BCF
2693
2424
3791
2684
11592
2705
2406
4195
3339
12645
Total Estimate about 14 Tcf
Damodar Valley Basin and Prospectivity of Shale Gas
Regional Stratigraphic Column of the Damodar Valley Basins
Shale Gas Resource Estimation
of Raniganj Area
• Two wells drilled by ONGC as R&D for shale gas
in Raniganj area.
• Based on the core and log data integration, best
estimate risked GIIP of 48 tcf has been made
covering an area of 879 sq. km.
Source ONGC
Source ONGC
Krishna-Godavari Basin
Source DGH/ONGC
Cauvery Basin
Ariyalur-Pondicherry sub basin
Kumbhkonam-Madnam-Portonovo
High
Tanjore-Tranquebar sub basin
Pattukottai-Mannargudi-Karaikal
High
Nagapattinam sub basin
Vedarniyam High
Pattukuttai-Manargudi high
Ramnad-Palk Bay sub basin
Mandapam Ridge
Gulf of Mannar sub basin
Vedarniyam – Tiruchirapally terrace
Source DGH/ONGC
Source DGH/ONGC/OIL
Average Depth (M) of Shale Units in Different Basins
Cambay
Basin
AssamArakan
Basin
Gondwana
Basin
KrishnaGodavari Basin
Cauvery
Basin
Vindhyan
Basin
Tarapur
Shale
(1200)
Bokabil
(2000)
Raniganj
(1000)
Vadaparru
(1000)
Karaikal
(1000)
Ganurgarh
(800)
Younger
Cambay
Shale(1500)
Bhuban
(2300)
Barren
Measures
(1200)
Palakollu
(1500)
Komaraks
hi
(1400)
Hinolta
(1200)
Older
Cambay
Shale(2000)
Kopili
(2500)
Barakar
(2000)
Raghavapuram
(2000)
Kudavasal
(2000)
Pulkova
(1500)
Kommugudem
(>2200)
Sattapadi
(3200)
Chakaria
Olive(1800)
Disang
(3000)
Source Oil & Maritine Journal by Dr. V.K. Rao
Characteristics of Shale Units in Different Basins
Cambay
KG
Cauvery
Assam
Arakan
Vindhyan
Gondwana
1.5-4.0
1.223.0
0.314.76
2.5-6.2
0.60-6.04
4.00->10
0.53-0.85
0.351.30
0.341.15
0.57-1.94
No data
0.40-1.20
400>1500
5001800
2001100
800-1200
75-320
150-900
II & III
II & III
II & III
II & III
III
TOC %
Vro%
Thickness
in Meters
Kerogen
Type
Prognostica
ted
Resource
Potential
(Tcf)
217
280
Source Oil & Maritine Journal by Dr. V.K. Rao
80
55
Not
known
III
85
DRAFT POLICY ANNOUNCED BY GOVT.
FOR SHALE GAS / OIL IN INDIA
• THROUGH OPEN INTERNATIONAL COMPETITIVE BIDDING
(ICB) PROCESS
• SUCCESSFUL BIDDERS TO SIGN CONTRACT WITH THE
GOVT. BASED ON THE MODEL CONTRACT
• IN CASE SHALE GAS BLOCK FALLS WITHIN AN EXISTING
OIL & GAS / CBM BLOCK THEN RIGHT OF FIRST REFUSAL
OFFERED TO THE EXISTING CONTRACTOR TO MATCH
OFFER OF SELECTED BIDDER. IN CASE THEY REFUSE,
THEN ENTER INTO MODEL CO-DEVELOPMENT /
OPERATING AGREEMENT FOR SIMULTANEOUS
EXPLORATION AND PRODUCTION.
•
GOVT. WILL ENSURE ALL STATUTORY, REGULATORY AND SECURITY
CLEARANCES ARE OBTAINED BEFORE BIDDING
•
EXPLORATION WILL BE AN ACCORDANCE WITH THE LAW OF THE LAND,
INCLUDING THE WATER ACT 1974, AIR ACT, 1981 AND UNDER
ENVIRONMENT PROTECTION MEASURES
•
PROVISION FOR OPERATING COMMITTEE AND SEPARATE STEERING
COMMITTEE
•
SHALE GAS IS PRODUCED OVER LONGER TIME SO MINING LEASE (ML) MAY
BE GIVEN FOR 30 YEARS. WITH PROVISION FOR AUTOMATIC EXTENSION, IF
NECESSARY.
•
THE SELECTED BIDS WILL BE FIRST APPROVED BY AN EMPOWERED
COMMITTEE OF SECRETARIES. THEREAFTER, FINAL APPROVAL BY CCEA.
•
PROVISION FOR ADDRESSING WATER MANAGEMENT ISSUES AND OTHER
ENVIRONMENTAL ISSUES.
FISCAL REGIME
• CONTRACTOR WILL PAY ROYALTY TO STATE GOVERNMENT.
• CONTRACTOR TO BID PRODUCTION LEVEL PAYMENT (PLP) ON A
SLIDING SCALE BASED ON INCREMENTAL PRODUCTION.
• COST RECOVERY WILL NOT BE ADMISSIBLE.
• COMMERCIAL DISCOVERY BONUS - USD 0.3 MILLION
• NO CESS PAYABLE ON SHALE OIL
• TO PAY APPLICABLE INCOME TAX AS PER INCOME TAX ACT 1961.
• THE GAS PRICING MECHANISM WILL BE UNDER BROAD DIRECTIONS
OF GOVERNMENT POLICIES.
Suggestions on Draft
Policy to attract
Technology
&
Investment
•Suggestion 1
Draft Policy states pricing of gas will be within the
framework of the Govt. Policies on Marketing and
Pricing of Gas.
This will be the main stumbling point in the shale gas
policy. Because Shale gas wells are drilled deeper,
drilled horizontally with multi stage fraccing, they
need huge quantities of water and proppants,
therefore, they cost 2-3 times more than conventional
wells. Without market driven price many wells will
not get drilled as per the experience of USA.
Experience of USA – maximum number of rigs
operate and maximum wells get drilled when shale
gas price is high.
•Suggestion 2
In the draft policy no income tax or fiscal
incentive provided.
It is suggested that at least in the first round of
Shale Gas to attract Companies with requisite
experience, technology and financial strength
some incentives may be considered.
Reasons
1. Interest of companies is fading in India.
Example NELP Rounds from I to IX
Exploration Blocks awarded in NELP Rounds
60
52
50
41
40
32
30
24
23
23
20
20
4
5
19
20
10
0
1
2
3
NELP Rounds
6
7
8
9
22
Reasons (Contd.)
2.
Very high cost of Shale Gas development (23 times more than conventional hydrocarbons).
3.
Lack of infrastructures available in the
country for shale gas. Very limited pipeline
network.
4.
Lack of sufficient sub-surface data which
will discourage private companies specially
foreign companies from investing due to
conceived high geological risk.
5.
Limited unconventional E&P experience in
the country.
6.
Very poor land and fresh water availability
being densely populated country.
Reasons (Contd.)
7.
Shale Gas production from very tight shales is
a highly complex and technically challenging
process. It will be necessary to provide incentives to
attract experienced oil companies with technologies
from abroad and also to encourage Indian companies
to invest money in this new kind of use of
technology, in a country where commercial presence
of shale gas is not yet established.
8.
According to EIA publications, April 2011 there
are 32 countries having 48 major Shale Gas Basins in
the world. Thus, India has to compete with many
countries to attract suitable Companies which can
bring technology, capital and management
capabilities.
India is competing with other countries to attract companies with shale gas
experience that will bring Technology, Capital & Management capabilities
48 MAJOR
SHALE GAS
BASINS IN 32
COUNTRIES
EIA estimates 6622 TCF
recoverable in the assessed
basins.
US: 862 TCF
* Only Rajasthan basin estimated
Source: EIA, April 2011
India: 63* TCF
Reasons (Contd.)
9.
When NELP and CBM Rounds introduced for the first time, the
Government provided 7 year tax holiday to attract companies to bid in
India. Now that even more complex and technology intensive Shale Gas
Policy is being announced it may be necessary to again consider 7 years
tax holiday.
10. If above is not feasible then a case should be build up for atleast 4 –
5 years tax holiday.
Shale gas wells decline very fast. To maintain production at reasonable
level for sale to industry, wells have to be drilled every 2 – 3 years
It is estimated that in 4 – 5 years only around 20% gas may get produced
out of entire life of field on which tax holiday will apply. This model can
be developed by DGH. The Govt. will still earn full tax on remaining 80%
of gas.
The Govt. is getting many other revenues from shale gas block as
royalty, central / state taxes and PLP etc.
•This will provide enormous incentive to drill as many wells as possible in the first 4-5
years and sell gas to consumers as early as possible. This is exactly what country needs
i.e. earliest possible gas production. The remaining 60% wells will get drilled later to
maintain the required production profile for sale of gas.
• Suggestion 3
“3.4
of draft shale gas policy states that areas
previously allotted and where development /
production phase has started shall be excluded from
offer for shale gas / oil exploration.”
Such areas in Cambay, KG, Cauvery, Damodar &
Assam- Arakan Basins hold the best shale gas/ oil
potential of the country. Thus, 60-70% of expected
resources will not get developed.
• Some options for considerations –
(a) When such blocks are offered and if the existing
operator of an oil & gas Block is the best bidder he will
automatically get the Block. If he is not the best bidder
then option is to give him a chance to match the best
bid. This could be unfair to the new bidder. It may be
better if the block is awarded to the best bidder but
original operator of Oil & Gas Block is given an option
to farm in upto 30% in the operations of the new bidder,
on payment basis.
(b) Ministry by transparent bidding process may allow
current lease holders of oil & gas blocks to download
part of their equity to companies with shale gas
experience and technology.
•Suggestion 4
In draft policy contract duration is 32 (thirty two) years and
divided into two phases- Phase I and Phase – II
•
Division in Phase-I & Phase-II may not be adequate. For
example in CBM Contracts there is minimum provision of 3
Phases and past 14 years of experience of CBM operations in
India shows that 3 phases are required.
Following phases and time frame may be considered:
•
•
•
Phase-I (5 years) – Exploration Phase with provision for
Exit at its end, if required.
Phase-II (minimum 3 years) – This can be called Drilling
of Pilot Wells Phase. Also includes Techno economic
feasibility, Market Survey and Commitments. With an
exit clause at its end
Phase-III (25 years) – Development & Production Phase
•Suggestion 5
•Bidding Parameters in draft policy
•Technical Qualifying Criteria– 3 years experience in oil & gas / CBM/
shale gas / oil.
•Weightage for Minimum Work Program – 40%
•Weightage for Production Linked Payments – 60%
•This will not give desired results based on the experience of pre-NELP
and NELP Rounds in the last 20 years. What could be considered–
% Weightage
Preferable mode
Minimum requirement
•
MWP
45
45
•
PLP
40
45
•
Technical Capability
15
10
Sl. No.
1.
2
Sub-criteria
% Weight- age
(a)
Oil & Gas Recoverable Reserves
(O+OEG)* in MMBoe for the previous 5
years
1
(b)
Shale Gas / Oil reserves in BCM/MMBoe
for the previous 5 years
1
(a)
Annual production of Oil & Gas
(O+OEG)* in MMBoe for the previous 5
years
1
(b)
Annual Production of Shale Gas/Oil in
BCM/ MMBoe for the previous 5 years
1
3
Acreage holding (in Sq. kms.)
(a)
Oil/Gas Block
1
(b)
Shale Gas / Oil Block
1
Sl. No.
Sub-criteria
% Weight- age
Bidder’s experience as an operator in
4
Exploration and production of oil and
gas for last 5 years
1
Exploration and production of Shale
Gas / Oil for last 5 years
1
5
Experience of working in India in Oil
and gas sector for last 5 years
1
6
Gas & Crude Oil transportation,
storage, distribution experience.
Gas utilization industry experience
(e.g. like Fertilizer, Petrochemicals,
Power, Steel etc.)
1
(a)
(b)