INDAI: DOMESTIC OIL PROSPECTS DIMINISH

• Document Type: CREST
• Collection: General CIA Records
• Document Number (FOIA) /ESDN (CREST): CIA-RDP88T00096R000300370001-9
• Release Decision: RIPPUB
• Original Classification: S
• Document Page Count: 39
• Document Creation Date: December 22, 2016
• Document Release Date: April 19, 2011
• Sequence Number: 1
• Publication Date: October 1, 1986
• Content Type: REPORT

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Directorate of
Intelligence 25X1
India: Domestic Oil
Prospects Diminish
Secret
NESA 86-10039
October 1986
Copy 3 0 6
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Directorate of Secret
Intelligence
India: Domestic Oil
Prospects Diminish
coordinated with the Directorate of Operation
This paper was prepared byl I Office
of Near Eastern and South Asian Analysis. It was
Comments and queries are welcome and may be
Secret
NESA 86-10039
October [986
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India: Domestic Oil
Prospects Diminish) 25X1
Key Judgments A detailed analysis by a contractor of India's natural resource base and the
Information available operation of its domestic oil industry suggests that oil production will
as of I August 1986 decline significantly from 600,000 barrels per day (b/d) in fiscal year (FY)
was used in this report.
1985 to 490,000 b/d in FY 1989 and 275,000 b/d by the end of FY 1994.
Rapidly rising domestic energy consumption, declining supplies of noncom-
mercial energy, and intractable problems in the coal and electrical power
sectors will force India to greatly increase oil imports or face slower
economic growth. Domestic oil production will cover only 40 percent of
demand in FY 1989, compared to about 65 percent in FY 1985.
Indian Government planners, while forecasting a growth in production to
690,000 b/d in FY 1989, have nonetheless demonstrated concern over the
prospects for increased oil production. A lack of new oil discoveries since
the mid- 1970s has prompted the government to lower its estimate of proved
oil reserves and to dramatically reduce its early 1980s projection of growth
in oil production. The government also has launched a major campaign to
enlist foreign oil companies in exploring newly opened offshore areas.
India's need to find more oil reserves and get maximum recovery from
producing fields will present the United States and other Western countries
with a market for high-technology goods and services. The degree and
terms of private foreign participation in the oil sector are hotly debated po-
litical issues in India, however, and government vacillation toward such
participation is hindering the establishment of a business environment that
would encourage more foreign investment.
The adverse impact of falling oil production on India's foreign payments
also will make it more difficult for New Delhi to increase purchases of
Western high-technology and capital goods needed to modernize the
economy and promote growth. India probably will seek more concessional
Western aid to finance development of its oil sector as well as its economic
modernization program to avoid a heavier hard currency debt burden.
The relative importance of the Soviet Union to Indian oil exploration and
development is likely to diminish. New Delhi will increasingly seek
Western technology and expertise both to explore in deeper water off shore
and complicated geological formations on shore and to maintain output
Secret
NESA 86-10039
October 1986
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from older fields. The Soviets can provide India with only second-rate
equipment and technicians. Moscow also will need more of its resources at
home to cope with its own production problems.
Deteriorating prospects for increased crude oil production are likely to have
an adverse impact on India's foreign trade balance. Demand for petroleum
could grow by more than 7 percent annually over the next several years if
Prime Minister Rajiv Gandhi continues his push for greater economic
liberalization and faster economic growth. The volume of petroleum
imports is almost certain to increase faster than the 8-percent average
annual growth projected by the government.
Increased oil imports will offset savings resulting from the fall in world oil
prices over the last year. If India's crude oil demand reaches 1.2 million
b/d by FY 1989, the oil import bill using a sustained world oil price of $10
to $15 per barrel would be $2.6-3.9 billion. India's oil import bill in FY
1985-with crude oil prices at slightly less than $30 per barrel-was about
$3.1 billion.
The most important constraint to increasing domestic oil production in
India is its resource base. According to a study conducted by the United
States Geological Survey, India's undiscovered recoverable onshore oil
reserves are probably spread over so extended an area that no new major
commercial reserves may be found. Analysis of the USGS report also
indicates India may have no economically viable offshore reserves beyond
those already discovered.
The most likely scenario developed by the contractor suggests that onshore
production will decline rapidly from the FY 1985 level of 200,000 b/d to
100,000 b/d by FY 1994. Discoveries in new areas probably will contribute
no more than 25,000 b/d in FY 1987 and decline to about 14,000 b/d by
FY 1994. Even this may be optimistic, since it assumes that discoveries in
virgin territories will be brought on stream continuously and without delay.
Technical analysis shows that offshore production will probably decline
from the FY 1985 level of 400,000 b/d to 350,000 b/d in FY 1987,
stabilize through the end of FY 1989, and decline to 175,000 b/d by the
end of FY 1994. The forecast of offshore production is based primarily on
output from the Bombay High field with a minor amount from small fields
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in the area. Outside the Bombay High area, the leadtimes involved in
developing new areas off shore almost guarantee that none will be
developed through FY 1989, and the outlook beyond that is not bright.
Prospects for increased natural gas production are more favorable, but,
without major new investment, gas production will be barely sufficient to
supply fertilizer plants already planned over the next few years. Further
development of known reserves and additional gas discoveries are not likely
to be a factor in this decade.
Problems within the domestic oil industry will be a major drag on India's
efforts to increase current production from known reserves and to exploit
new fields. Indigenous drilling capabilities and management techniques are
poor by Western standards. The Indians do not have the technology or
expertise required for sophisticated exploration and development in the
severe operating environments and/or the complicated geology where new
Indian discoveries are likely to be found.
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Contents
Key Judgments
Contrasting Production Outlooks
Indian Government Projections
1
Alternative Production Outlook
2
Proved and Probable Reserves
2
Capability of Domestic Oil Industry
5
Western Contractor Participation
6
Soviet Participation
7
Onshore Production Potential
7
Offshore Production Potential
10
Prospects for Smaller Bombay Offshore Fields
11
Natural Gas Prospects
12
Implications for India's Economy
14
Implications for the West
15
The Soviet Role
15
Appendixes
A. Difficulties in Interpreting Indian Petroleum Reserves Data
17
B. Contractor's Methodology for Forecasting Production
C. The Geology and Potential of India's Major Basins
I l
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Figure 1
The Indian Oil and Gas Industry
Pakis
Bombay Highn
Arabian
Sea
Bona d~` 'Ahmfid id
Rajkot Khablr~f? Vadodara
(Barodq
(C?mboi)
North Bassein
ombay
'An
South Bassein
%Anklesver
(Hazi J~Kosombe Tapf
azirr a
rat
Central
Tapti
South
Gulf Tapti
of
Khanlbhat 100 Kilometers
(C.imb.ty)
Proposed gas pipeline
("H-B?J" pipeline project)
Madras
Oilfield
CD Gasfield
Crude oil pipeline
Petroleum products pipeline
Oil refinery
0 400 Kilometers
l Ir
0 400 Miles
Calcult
Haldi>~.i
Burma
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India: Domestic Oil
Prospects Diminish
In the late 1970s, prospects for India's future oil and
gas production brightened with the development of
the offshore Bombay High field-India's largest oil-
field-and increased government support for offshore
exploration by foreign companies.' Some Indian offi-
cials publicly speculated that the country had a
chance of achieving oil self-sufficiency.
year (FY) 1985.' The Bombay High field accounts for
about two-thirds of national production. Most remain-
ing production comes from onshore fields in Assam
and Gujarat.
India also produced about 790 million cubic feet per
day (cf/d) of natural gas in FY 1985, the equivalent of
about 135,000 b/d of oil. Associated gas from the
Bombay High area accounted for slightly over half of
Increasing domestic oil production in the early 1980s
helped India maintain economic growth while lower-
ing its trade deficit. Domestic production provided
about 65 percent of India's oil consumption last year.'
The Indians still are forecasting some growth-or at
least maintenance-of current oil production levels
through the remainder of this decade. In contrast, a
CIA contract study projects a sharp decline in Indian
oil output through 1995.
India's crude oil output has increased by an average
of 13 percent annually since the beginning of commer-
cial oil production from the Bombay High oilfield in
1976 to about 600,000 barrels per day (b/d) in fiscal
in 1986, almost all from Saudi Arabia, Iran, Iraq, Kuwait, and the
United Arab Emirates. About one-fourth of these crude imports
will be delivered on Soviet account under the Indian-Soviet trade
agreement and will not require hard currency payment. New Delhi
will also import an estimated 90,000 b/d of petroleum products.
domestic gas production. Most of the remaining gas
came from fields in Assam and Gujarat.
Contrasting Production Outlooks
sufficiency.
Indian Government Projections
The official projection presented in the Indian
Government's seventh economic development plan
published in 1985' calls for production of 690,000
b/d in FY 1989, an increase of about 100,000 b/d
over the FY 1985 rate, but a review of public
statements by Indian officials suggests that many are
dubious about reaching this level of oil production.
The US Embassy reports that Indian estimates of
production in FY 1989 now range from 600,000 b/d
to 700,000 b/d-roughly the official estimate of
future production. The Minister of State for Petro-
leum presented before Parliament last November
production estimates of 610,000 b/d for FY 1986,
630,000 b/d for FY 1987, and 640,000 b/d for
FY 1988. There is no longer Indian talk of self-
India estimates that natural gas production will in-
crease to about 1.5 billion cf/d in FY 1989, according
to the government's development plan. Offshore
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production from a natural gasfield currently being
developed is projected to become a major factor in the
energy scene in FY 1987 and by FY 1989 will account
for about half of India's natural gas production.
Offshore associated gas-natural gas produced along
with crude oil-from the Bombay High field is pro-
jected by India to peak in FY 1987 and then begin a
fairly rapid decline to 390 million cf/d in FY 1989.
Total onshore associated gas production will remain
fairly constant at about 300 million cf/d.
Alternative Production Outlook
A CIA contractor concludes that Indian crude oil
production will decline to 490,000 b/d in FY 1989
Figure 2
India: Oil Production, FY 1955-85
and 275,000 b/d in FY 1994. This estimate is based 0 1955 60 65 70 75 80 85
primarily on estimates of India's reserve base and the
limitations of the domestic oil industry that are more
pessimistic than those of the Indian Government. A
detailed look at the distribution of oil-bearing geologi-
cal formations in India suggests that the country's
undiscovered recoverable oil reserves of 1.4 billion
barrels are contained in so extended an area that no
major new commercially viable reserves may be
found. Even if commercial reserves are found, they
probably will require sophisticated and expensive
Western expertise and equipment for exploitation and
are not likely to result in significant production
increases in this decade. Prospects for natural gas are
more favorable, in the contractor's judgment, and
production should exceed 1 billion cf/d by FY 1989.
Figure 3
India: Natural Gas Production,
FY 1973-85
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The Indian Government uses an unrealistically high
estimate of the country's oil reserves based on outdat- 0 1973 75 80 85
ed and unsophisticated Soviet surveys, according to
the contractor. In its current plan, the government
estimates total geological reserves of oil and gas at
124 billion barrels but does not indicate what percent
is recoverable. Two different joint Soviet-Indian
teams estimated total recoverable oil and gas at
between 41 billion and 46 billion barrels:
? In 1975 another team estimated ultimately recover-
In 1965 a team estimated India's ultimately recov- able reserves at 11 billion barrels of oil and 35
erable oil and gas reserves, including reserves al- billion boe of natural gas.
ready produced, at 29.2 billion barrels of petroleum
liquids (oil) and 12.2 billion barrels of oil equivalent
(boe) natural gas.
Secret 2
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Over the last three years, the Indian Government has
steadily lowered its official projections of oil produc-
tion. In late 1982-early 1983, the Oil and Natural
Gas Commission (ONGCJ, the state company respon-
sible for most domestic oil and gas exploration,
presented two scenarios for future oil production-
one called for 900,000 b/d and the other for 1.2
million b/d in 1990. Indian planners believed that 1.2
million b/d or self-sufficiency could be reached if the
government was willing to finance the necessary level
of exploration and development. The lower level of
900,000 b/d was not seriously questioned at that time
but merely accepted as attainable.
By mid-1985, however, the government had become
more pessimistic and revised its official estimate of
production for FY 1989 to 690,000 b/d. We believe
Indian planners lowered their estimate in large part
because no major new oil discoveries have been made
in over a decade. The US Embassy in New Delhi
reported that the government's earlier estimate of
900,000 b/d assumed 200,000 b/d would come from
fields that had not been discovered. We believe the
government's more recent lower estimate also took
into account lagging foreign interest in offshore areas,
the domestic oil industry's poor drilling record, and
the high cost of increasing output from older matur-
ing fields.
Government Plans for Oil Production
The government projection of 690,000 b/d in FY 1989
calls for onshore deposits to provide most of the
increase in production, primarily the Cambay Basin,
Upper Assam, and Nagaland. Nearly half the in-
creased production is to come from the Cambay
The contractor study indicates that the estimates of
ultimately recoverable oil and gas reserves derived by
the joint Soviet-Indian teams are two to five times too
high. In 1984 the United States Geological Survey
(USGS) estimated the most likely level of undiscov-
ered potential oil and gas reserves at 1.4 billion
barrels of oil and 2.85 billion boe of natural gas.' To
' The USGS placed no limit on the time allowed for exploitation
and did not assess the economics of prospective finds when making
its estimates of ultimately recoverable oil. Potential reserves in the
vast area outside the Bombay High will be expensive and time
consuming to find, in the contractor's judgment. Some of the
estimated undiscovered reserves will not be produced for decades-
Basin, where oil production is projected by the gov-
ernment to increase from 78,000 b/d in FY 1984 to
120,000 b/d in FY 1989. The government expects to
achieve the increase primarily through final develop-
ment of the Kalolfield and development of heavy
oilfields north of Gujarat.a The other half of the
overall increase in production is projected to come
from fields in Upper Assam and Nagaland, where
production is expected to double from the FY 1984
level to about 90,000 b/d in FY 1989. In other aging
producing areas, the government is hoping to main-
tain current levels of production through additional
development drilling and improved well maintenance.
The government plan called for only a small increase
in offshore production. The main effort would be
devoted to drilling additional development wells and
expanding the water injection program to prevent a
decline in Bombay High field production. Lower oil
prices, however, have sparked a debate between the
government and the state oil company. The central
government is now considering a slowdown in work on
part of the Bombay High field. The plan also calls for
about 20,000 b/d of additional production from
Heera, a small field in the Bombay High area.
a Some additional production may come from Gandhar in the
Cambay Basin. Oil was discovered in 1983, and early this year the
government claimed the field as India's second-largest geological
reserve of oil after the Bombay High field. Exploration, however, is
still under way, and the US Embassy does not believe sufficient
drilling and evaluation have taken place to confirm the size of the
reserves or the production potential. If commercial production is
developed, it may only make up for declining output in other
adjust the USGS estimates to the Soviet-Indian esti-
mates, 4.8 billion barrels of already discovered and
partly produced oil must be added to the 1.4 billion
barrels undiscovered, yielding ultimately recoverable
oil reserves of 6.2 billion barrels. Adding in natural
some perhaps never because, while they are technically recoverable,
it may never be economical to do so. The relative sparseness of
estimated reserves relative to geographic area outside current
producing areas substantially increases the risk of not finding
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Figure 4
Projections of Indian Oil Production,
FY 1984-89
600
Indian
government
projection
Contractor's
projection
I I I I I I
0 1984 85 86 87 88 89
India's Undiscovered Recoverable
Oil and Gas Reserves a
Undiscovered Reserves at Three Different
Levels of Probability
95 Percent
Most Likely
5 Percent
Oil reserves
(billion barrels)
0.73
1.41
7.14
Gas reserves
(billion cubic feet)
8,870
16,530
61,660
a Total undiscovered reserves are derived from a
simulation process involving all the basins and do
not equal the sum of the estimates for the individ-
ual basins.
Figure 5
India: Projected Gas Production,
FY 1985-89
Indian
government
projection
Contractor's
projection
I I I I I
0 1985 86 87 88 89
gas, the figure reaches 9 billion barrels of oil and oil
equivalent, which is only about 20 percent of the 1975
Soviet-Indian estimate of 46 billion barrels of oil and
gas. Even the USGS's most optimistic estimate-with
only a 5-percent probability of occurrence-is only
22.6 billion barrels, or about half the 1975 estimate.
The contractor's independent evaluation is even more
pessimistic than the USGS report. The contractor
considered the USGS estimate of 3.3 billion barrels of
discovered oil in the Bombay High area about 10
percent too high. The Indians claimed that proved and
probable reserves in the Bombay High were 2.5 billion
barrels in FY 1983. As a result, the contractor
believes discovered reserves (which include reserves
already produced) should be at least 300 million
barrels lower than the USGS estimate because 540
million barrels had been produced by India from
Bombay High through the end of 1984. Because of
the methodology employed by the USGS, an overesti-
mate of identified or discovered reserves will lead to
an overestimate of undiscovered reserves by a similar
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proportion-an important distinction, since the Bom-
bay High accounts for a large share of production in
the USGS estimates.
Although the Indian Government continues to use the
optimistic oil reserve base derived from estimates
made in the 1960s and 1970s, its official estimate of
proved and indicated balance reserves reflects some
pessimism in the Ministry of Petroleum (see appendix
A). For the first time since the early 1970s, the
government is beginning to lower its estimates of
proved and indicated balance reserves. The govern-
ment's estimates peaked in FY 1983 at 3.8 billion
barrels and are now at 3.6 billion barrels. We believe
this indicates a more realistic attitude among govern-
ment officials in response to the lack of new discover-
ies over the last 10 years.
Capability of Domestic Oil Industry
India's strategy for increasing oil production over the
next few years is based on the assumption that most of
the remaining reserves are in small deposits, will
require deep drilling, and will be expensive and time
consuming to exploit. The current five-year plan calls
for intensified exploration in known oil-producing
areas and extending the search to inadequately ex-
plored and unexplored areas. The government intends
to drill 2.8 million meters of exploratory wells during
the current five-year plan period, nearly triple the
drilling in the previous plan period. To carry out this
ambitious exploration program, the Ministry of Petro-
leum plans to have over 120 active rigs by 1990-
more than double the current number.
The government almost certainly will need substantial
foreign assistance if it is to come close to its targets.
Evidence compiled by the contractor suggests that the
domestic Indian oil industry will have a difficult time
doubling the number of rigs and operating them
efficiently enough to triple exploratory drilling. Indig-
enous drilling capabilities are poor by US standards,
and a strong tendency toward centralized micro-
management hinders efficient employment of India's
existing fleet of rigs. The state oil companies missed
their onshore drilling targets in FY 1984 by more
than 25 percent and offshore targets by about 30
Figure 6
India: Ministry of Petroleum
Estimate of Proved and Probable
Crude Oil Reserves, FY 1965-85
Billion barrels
Bombay
offshore
Gujarat
Assam
1965 70 75 80 85
Fiscal year
insufficient to back them up.
In addition to inefficient use of the rigs currently in
operation, India is unlikely to be able to increase the
number of active rigs much over the next few years.
Most new rigs are only replacing old ones, and this
situation is likely to continue for some time because of
the age and poor condition of the existing rigs.
Government documents show a cutback in funds
requested by the Ministry of Petroleum for the sev-
enth five-year plan from $1.8 billion to $1.1 billion.
Even if the rigs were available, the contractor's
evaluation of past drilling performance indicates that
experienced personnel would not be available to man
and manage them, and support services would be
The Indian oil industry also will have a difficult time
locating new oil deposits that are likely to be in
complex geological formations rather than in more
easily identifiable ones. Locating these subtle forma-
tions will require detailed seismic surveys and a large
increase in seismic data processing at a time when
India already has a several-year backlog of unpro-
cessed seismic data. The Oil and Natural Gas
percent.
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Figure 7. India will have to drill more wells on
shore to meet the government's production goals.
Commission (ONGC) has limited data-processing ca-
pability and is reluctant to release the data to foreign
contractors for processing
DOnce small geological formations containing
oil are found, sophisticated drilling and well servicing,
completion, and production techniques-now only
available from foreign contractors-will be required
to make them profitable.
Western Contractor Participation
India probably will be unable to attract sufficient
foreign participation in drilling or acquire enough
sophisticated oil industry technology to achieve its
production goals.
India's efforts are being hamstrung by the vacillating
policies of the Ministry of Petroleum and the relative-
ly poor terms being offered to contractors. Although
the Ministry of Petroleum has successfully encour-
aged the formation of 15 joint ventures during FY
1984 and FY 1985 between foreign drilling companies
and private Indian partners, and these 15 ventures
have already bid on ONGC tenders for drilling
services, Indian restrictions guarantee that many of
the newly formed joint ventures will never drill in
India. Once the bids were submitted, the ministry
announced that the mere provision of rigs or other
equipment could not be construed as equity in the
ventures and that such joint ventures would ha; a to
procure all their equipment through competitive
global bidding without preference to the foreign part-
ner.
On the basis of current low oil prices and the disap-
pointing experience of foreign oil companies, the
contractor believes the limited size and widespread
distribution of remaining petroleum resources also
will limit the willingness of contractors to risk their
financial resources to explore for oil in India. Most
potential oil deposits do not appear to offer a return
large enough to satisfy the central government and
cover the costs of private contractors. Many firms
probably have written off participation in India as not
economically feasible because of the low expected
payoff as well as the difficulty in working with the
Indian Government. A US oil company that drilled
only dry holes in one of India's best potential areas
adjacent to Bombay High and other firms that have
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drilled offshore areas in the past are not likely to
return to India without clear prospects for oil discov-
eries. The reduced budgets of Western oil companies
for exploration prompted by low oil prices also are a
strong limiting factor on foreign oil company interest
Soviet overseas technical assistance missions use infe-
rior equipment and their least qualified technical
personnel.
in India.
Nonetheless, India is making a strong effort to attract
bidders. The members of the Indian delegation to the
Offshore Technology Conference in May 1985-
consisting of ONGC president Colonel Wahi, ONGC
member Dr. A. K. Malhotra, and other top officials-
had as their first priority discussions with prospective
bidders to find out what terms would be required to
ensure a successful lease offering, according to at-
tendees at the conference. The government has tried
to take account of its findings in its recent invitation
to foreign companies to explore for oil and gas in 27
offshore blocks. New liberalized terms include a
greater share of oil production for the foreign operat-
ing companies, no royalty payments to India, and the
elimination of minimum spending commitments or
bids. Foreign companies have until 30 November
1986 to submit bids.
Soviet Participation
Thirty years of Soviet involvement in the Indian oil
industry will hamper New Delhi's efforts to incorpo-
rate more Western technology and techniques. Soviet
and Western equipment and methodologies are not
always compatible, making a change slow and ineffi-
cient. Many in the Indian bureaucracy are reluctant
to change from known patterns, while others believe
that the Soviet Union is a more reliable partner.
Nevertheless, on the basis of New Delhi's interest in
acquiring more Western technology and Moscow's
domestic oil problems, the contractor argues that
Soviet influence and participation in the Indian petro-
leum sector probably have peaked. The experience of
exploiting the offshore Bombay High field has
brought Indian managers and key technical personnel
into close contact with Western firms having superior
equipment, materials, and technology. The Soviets, in
contrast, have little experience with offshore petro-
leum technology and have little to offer India in this
Onshore projects designed and implemented under the
auspices of the World Bank have demonstrated to the
Indians the technical efficacy of Western state-of-the-
art well-servicing and stimulation techniques. If
ONGC cannot afford the outlays involved in having
these services performed by Western contractors, it
probably will try to develop the technology domesti-
cally.
Still, Soviet influence and participation in the Indian
petroleum industry is evident at all levels of operation,
from India's use of Soviet-style estimates of reserves
and resources-conducted by Soviet-led teams-to
onshore drilling and production operations using Sovi-
et methods. Soviet influence is enhanced because
many Indian engineers and managers are Soviet
trained, several have married Soviet citizens, and they
travel frequently to the Soviet Union.
Agreements with the Soviets allow India to expand oil
exploration relatively cheaply. Under a protocol
signed with the Soviets in February 1986, the Soviet
Union will carry out intensive integrated exploration
over the next 10 years in 5,100 square kilometers of
the Cambay Basin in Gujarat and 3,100 square
kilometers in the Cauvery Basin in Tamil Nadu. The
agreement calls for preparation of a detailed feasibil-
ity report, execution of geophysical surveys, process-
ing and interpretation of data, drilling of exploratory
wells, and preparation of development schemes. The
US Embassy in New Delhi reports the Soviets have
allocated a credit of 300-350 million rubles at 2.5
percent interest to cover 70 percent of the project cost.
A previous commitment by the Soviets included two
workover rigs with Soviet crews to rehabilitate 120
wells in the Cambay Basin during 1983-85.
The contractor estimates that insufficient oil will be
found on shore to forestall production declines in the
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Figure 8
Indian Offshore Oil Exploration Blocks
D2dra and Nagar Haveli Orissa
1 !_
ombay ivianarasntraJ
} Vishakhaipa n
S :;; Frre rn ~r t
hineso `J-,~. ?,ndan
Punjab
NEW DELHitDJ
0d,Pradesh
L-- 1- ( U-, . _ , Rihar
400 Kilometers
400 Miles
~'p est
Ahmad8h8d '~ S hA~.?Ih"~ P-4oc h .~? ____~ 11NA
--J-- 'Calcutta
Vadoda-a ? Haldia
Isar~d~ L .
India f~ J
J
Pradesh
7~ Karnataka(
~MMadr's.
'Cl
Tamil
K. ala~ Nadu
D
oMaldives
ANDAMAN
ISLANDS
(India)
0 Andaman
and
Nicobar
Islands
NICOBAR oa
ISLANDS
(India)
L.^. a J
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Figure 10
India: Contractor's Estimate of Onshore
Crude Oil Production Potential, 1983-95
Thousand barrels per day
240
Maximum
feasible
Currently
producing
basins
next five years, given the size and nature of undiscov-
ered recoverable reserves. India's petroleum discover-
ies in the last decade barely kept pace with the
amount of oil produced. Significant reserve increases
claimed by the Ministry of Petroleum since 1980-81
are attributable primarily to improved oil recovery
estimates rather than new discoveries. Special en-
hanced oil recovery techniques only serve to slow the
rate of decline in existing production over the next 10
years.
ously and without delay.
The maximum feasible onshore crude oil production
India can attain over the next decade, according to
the contractor's analysis of the geologic potential, is
200,000 b/d, only a slight increase over current
output instead of the 80,000 b/d increase being
projected by the Indians. The most likely scenario,
however, shows onshore production declining rapidly
after FY 1987 to about 100,000 b/d by FY 1994.
Discoveries in new areas can be expected to contribute
no more than 25,000 b/d in FY 1987 and decline to
about 14,000 b/d by FY 1994. We believe this
estimate is optimistic because it assumes that discov-
eries in new areas will be brought on stream continu-
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Figure 12
India: Contractor's Estimate of
Offshore Crude Oil Production,
1985-95
Thousand barrels per day
Despite an active exploration effort in recent years,
there has been a notable lack of commercial success in
new areas on shore. Estimated undiscovered recover-
able reserves in these areas are too small and too
dispersed geographically to warrant crediting them
for a significant assured production in the next de-
cade, according to the contractor's review of the
geologic potential. If the Indians were to substantially
upgrade the efficiency of their operations and produce
from existing reserves at a faster rate, the decline
could be postponed temporarily, but probably only at
the expense of a more rapid decline later.
Special schemes to improve the recovery from known
oil deposits have been considered by ONGC to boost
onshore oil production. In the Cambay Basin, for
example, two thermal pilot projects and a chemical
pilot project have been proposed. Special enhanced
recovery methods probably will not materially affect
India's oil production in the next 10 years because
the methods proposed by
India so far have not proved commercially viable.
Even if pilot tests are successful, the leadtime re-
quired to analyze the results and to design and
implement a fieldwide project make it unlikely that
these methods can be implemented by India on a field
scale within the next 10 years. Moreover, even if India
were successful in applying special recovery schemes,
the contractor's analysis shows that recoverable re-
serves are too small to make a significant impact on
production.
.Other Bombay
offshore fields
Bombay
High field
The contractor's review of the geology and exploration
already undertaken indicates that offshore crude oil
production over the next five years will depend almost
exclusively on production in the Bombay High field.
The Bombay High field will continue to dominate
output because of the poor prospects of finding more
recoverable offshore reserves, the small sizes of re-
maining undrilled structures, and the poor character-
istics of the smaller fields in the remainder of the
Bombay High area. The government is producing
from two of the smaller marginal fields in the area-
Ratna and Heera-and is evaluating the economic
prospects of producing from eight others.
The contractor evaluation of offshore production
shows a decline from slightly more than 400,000 b/d
in FY 1984 to about 350,000 b/d in FY 1987,
stabilized output through FY 1989, and a decline
thereafter to about 175,000 b/d by FY 1994. This
contrasts with the Indian Government's assessment
that it may be able to increase offshore production
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the experience in offshore fields around the world that
have been produced under the duress of either meet-
ing national energy requirements or earning a profit
in exceptionally capital-intensive oil-producing areas
such as the North Sea.
Outside of the Bombay High area, the leadtimes
involved in developing new areas off shore almost
guarantee that none will be developed through FY
1989. Even beyond FY 1989, prospects for new areas
off shore are not bright.
The USGS report indicates that India's most likely
remaining offshore potential is less than 1 billion
barrels of oil. This is very small considering the large
area involved and creates a high risk that no commer-
cial reserves will be found in any given basin. The
offshore Krishna-Godavari Basin is a case in point. It
was once touted by ONGC and the World Bank as a
potential major addition to national petroleum re-
serves. Yet, to date, the largest field discovered is no
more than one-fifth the minimum economic field size
of about 100 million barrels.
The contractor's analysis of ONGC's offshore drilling
capability, average and incremental well productivi-
ties, and other data on the Bombay High field
indicates that the peak production rate achieved in the
field-400,000 b/d-does not represent drilling or
facilities constraints. The contractor estimates that
the field could reach a production level of more than
500,000 b/d. Nevertheless, it is clear from the many
references by Indian officials to the fact that Bombay
High production has peaked that New Delhi does not
intend to continue producing at such a high rate. The
contractor believes that India has decided against
higher rates of production because this would lead to
premature water and gas encroachment, substantial
loss of recoverable reserves, and rapid field production
decline.
Prospects for Smaller Bombay Offshore Fields
the satellite offshore fields-eight small marginal
fields 6 in the area surrounding the giant Bombay
High field-are not likely to be developed in the
foreseeable future because of current low oil prices
and the poor prospects for significant production.
prices that have been observed in recent years will
lead to at least a temporary shelving of most projects.
Even if the fields were developed, production would be
inconsequential in terms of national output.
6 Marginal fields in the offshore environment are those not suffi-
ciently profitable for installation of permanent production facilities.
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Natural Gas Prospects
In the contractor's judgment, natural gas output
should exceed 1 billion cf/d by FY 1989. Output from
an offshore gasfield scheduled to begin production in
the next year will more than compensate for the
expected decline in offshore associated gas. Onshore
natural gas output will probably remain relatively
stable through the mid-1990s. Gas-oil ratios of mostly
onshore associated gas production will rise slightly,
offsetting the effect of oil production declines.
Development of the giant South Bassein gasfield
discovered in the Bombay offshore area in 1976 is
under way. As of mid-1980, seven exploration wells
had been drilled on the South Bassein structure. The
field is now estimated to contain recoverable reserves
of 7 trillion cubic feet of gas, about 1.2 billion boe.
cated consuming facilities.7
The estimated plateau production rate of the field is
about 700 million cf/d when fully developed. This is a
fairly conservative rate, but it is designed to provide
stable field production over a 20-year period because
of the need for long-term production to supply dedi-
from outside contractors.
Development of South Bassein gas reserves is now
well advanced after having been postponed for several
years-most recently because of the discovery that
the gas contained corrosive hydrogen sulfide, requir-
ing respecification of all offshore handling facilities
for sour gas service. ONGC will conduct drilling and
pipelaying operations on its own, with little or no help
The first of three planned phases of field development
started in September 1985 and is scheduled to be
completed this year with a production capacity of 350
million cf/d. The first phase will consist of four
platforms, one each for production, utilities, flaring,
and living quarters. The production platform will have
seven gas wells. Two of the seven wells will be
reserved for prolonged testing of the oil zone, but
there are no plans to produce oil. The second phase
also will have a production capacity of 350 million
cf/d and is scheduled to begin producing in April
1988. By 1989, with the addition of two more remote
well platforms in Phase 3, the field should be produc-
ing at a plateau rate of 700 million cf/d, assuming
transportation and consuming facilities are completed
as scheduled.
South Bassein gas will be brought on shore through a
36-inch subsea pipeline to Hazira, the starting point
for the major Hazira-Bareilly-Jagdishpur trunk pipe-
line. A French-Japanese consortium was awarded the
' The South Bassein gasfield also has an oil column 3 to 5 meters
thick, which contains about 1.4 billion barrels of oil. A reservoir
engineering firm hired by ONGC to assess the field's reserves
estimated that only about 5 percent-70 million barrels-would be
recoverable. The recovery rate is low because of the thinness of the
oil column and underlying water, which probably will quickly
invade the production stream. Water encroachment also could
substantially reduce recoverable gas reserves. If ONGC decided to
recover the oil, the contractor believes the maximum achievable
production rate from the field would be no more than about 18,000
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$1.6 billion contract to build the line in April 1986,
after more than two years of negotiations, by offering
a package that included concessionary financing to
help meet the foreign exchange costs and substantial
participation by Indian companies. When completed
in 1989, the line will run 1,800 kilometers through
Maharashtra and Madhya Pradesh and terminate in
Uttar Pradesh at Babrala (near Bareilly), with a
major branch running southeast to Jagdishpur, not far
from Lucknow.
Six natural-gas-based fertilizer plants, now under
construction or on the drawing board, will be built at
various points along the line. Two other fertilizer
plants will be supplied with gas directly from the
Hazira terminal.
Without major new investment, however, the govern-
ment is unlikely to have sufficient gas to supply three
power plants and two refineries planned for operation
in the late 1980s and early 1990s. Natural gas
planners had envisaged accelerating the development
schedule of marginal Bombay offshore fields and
producing all of them at maximum feasible rates.
Production from this area would have provided the
additional gas supplies for the new plants. With the
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cutback in government funds available to the petro-
leum sector, the marginal Bombay offshore fields
probably will not be developed, and the power plants
and the refineries will be delayed and may not be
built.
Implications for India's Economy
We believe the deteriorating prospects for increased
crude oil production will have a serious adverse
impact on India's economic growth if world oil prices
rise much above current levels. New Delhi will have to
increase oil imports to meet domestic needs or bring in
more foreign oil company services to sustain output.
Either option would increase the oil sector's need for
foreign exchange and deny New Delhi these funds for
other development-related projects.
Recent trends point to demand for petroleum products
growing by at least 7 percent a year, slightly above
the government projection of 6.4 percent. The volume
of petroleum imports is almost certain to increase
faster than the 8-percent average annual growth
projected by the government, particularly as Prime
Minister Gandhi pushes for faster industrial growth.
Liberalization measures are making more automo-
biles available, many manufacturers are using diesel
generators to maintain production when electricity
from the public grid fails, and many farmers have
turned to diesel pumps for irrigation.
Figure 16
India: Oil Import Costs, FY 1984-89
Billion US $
Government Oil Production Projection
Per barrel
0 1984 85 86 87 88 89
Contractor Oil Production Projection
Per barrel
$20
$15
$10
I I I I I I
0 1984 85 86 87 88 89
Fiscal year
Increased oil imports will offset India's savings from
lower world oil prices. If India's crude oil demand
reaches 1.2 million b/d by FY 1989, the oil import
bill using the contractor's estimate of production and
a sustained world oil price of $10 to $15 per barrel
would be $2.6-3.9 billion. India's oil import bill in FY
1985-with crude at slightly less than $30 per bar-
rel-was about $3.1 billion. We believe declining oil
production will add to India's financial gap in FY
1989 unless oil prices remain near the $10 per barrel
level
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India's desire to find more oil reserves and get
maximum recovery from producing fields will present
Western countries with a potential market for the sale
of high-technology goods and services. Offshore ex-
ploration, particularly in deep waters, will require
expertise and technology that India does not possess
and the Soviets cannot provide. The onshore search
will require sophisticated oilfield services, particularly
in seismic analysis, to find the small deposits that
undoubtedly exist but are hard to detect. Special oil
recovery techniques contemplated by India to maxi-
mize output from known fields will also require the
assistance of outside experts.
The foreign payments impact of constant or falling oil
production, however, will make it more difficult for
New Delhi to increase purchases of Western oilfield
equipment and services and other high-technology
and capital goods needed to modernize the economy.
India probably will seek more Western aid and con-
cessional financing to finance oil exploration and
development.
The Soviet role in the Indian oil industry should
diminish. India will continue to look to the Soviet
Union for inexpensive and basic oil exploration assis-
tance, but we do not believe the Indians expect much
assistance in high-technology areas. Moscow has little
experience in offshore production, particularly in deep
water. The level of its onshore exploration capabilities
and the availability of sophisticated services from the
USSR also are limited. Moscow's problems in main-
taining domestic oil production and its requirements
for oilfield services and skilled oilfield workers in its
domestic industry will also make it difficult for the
USSR to increase its role abroad. The Soviets already
have declined an Indian invitation to explore the
onshore West Bengal Basin or areas in the Himalayan
foothills, according to press reports.
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Appendix A
Difficulties in Interpreting
Indian Petroleum Reserves Data
The method used by India to classify its petroleum
reserves is borrowed directly from the Soviet system.
The Indians have six categories of reserves-A, B,
Cl, C2, D1, and D2-which are differentiated ac-
cording to the degree of certainty concerning their
existence and recoverability. "A" reserves are drilled
and producing, while "D2" reserves are almost com-
pletely hypothetical with only the sparsest data to
back them up. The six categories are divided between
"balance" reserves (A, B, Cl) (so named because they
are entered on a balance sheet), which are completely
or largely identified, and "prognosticated" reserves
(C2, D1, D2), which are based on extrapolation and
speculation about new areas and enhanced recovery
potential.
Balance Reserves
India's system does not correspond exactly to either
the Soviet or Western systems and thus leads to
uncertainty when comparing to either proved or prob-
able reserves in other systems. The Indian Ministry of
Petroleum officially reports "proved and indicated
balance recoverable" reserves, which contains all A,
B, and C1 reserves. This differs from the Soviets, who
include only 10 percent of Cl reserves in their balance
and count the remaining 90 percent of C1 reserves as
prognosticated reserves. It also differs from Western
definitions in which A plus B reserves are very close to
proved reserves.
India's reporting of balance reserves is often described
in Western terms by the Indian press or other observ-
ers as "proved and probable reserves" or "proved
reserves." This is misleading because Indian proved
and indicated balance recoverable reserves are more
inclusive than Western proved and probable reserves,
although by how much is impossible to determine.
The contractor could find only one instance in recent
years-1978-when the Indians released disaggregat-
ed estimates of proved and indicated balance recover-
able reserves. As a result, almost no direct informa-
tion is available about the breakdown between what
are proved reserves and can be used for production
planning and forecasting over the next several years,
and what are probable or possible reserves and might
contribute little, if anything, to production pros-
pects-especially in the near term.
Another definitional problem causing confusion over
the Indian reserves classification system arises be-
cause it includes information on the amount of total
geological reserves of oil associated with recoverable
reserves for each category of reserves. Sometimes
Indians will refer to total oil reserves simply as
reserves or even proved geologic reserves-causing
misunderstanding among Westerners who associate
the terms proved and reserves exclusively with recov-
erable oil.
India has shown an increasing tendency to overesti-
mate proved and indicated balance recoverable re-
serves, according to the contract study. In 1980, India
claimed offshore oil reserves that were almost equal to
the expected ultimate recovery from the Bombay
High field as reported in World Bank documents, but,
in FY 1983, India raised its estimated offshore oil
reserves from 1.75 billion barrels to about 2.5 billion
barrels without any new commercial discoveries. Most
of the increase was due to an upward revision of
reserves at the Bombay High field because of much
better than expected reservoir performance to date. In
the contractor's judgment, this performance may be
due to overproduction of the field and disregard for
sound engineering practice and lagging development
of field facilities. The contractor believes there is a
high risk that recoverable reserves from the Bombay
High field will be substantially less than the Indians
now estimate.
India also is probably including estimates of recover-
able oil from the application of enhanced (tertiary) oil
recovery (EOR) methods at Bombay High in its
reserves estimates. Ninety percent of the 750-million-
barrel upward revision to official reserves since 1980
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was entered into the books in 1981, following the
second major OPEC-related oil price rise in 1979,
which convinced many observers that no end to rising
oil prices was in sight. Although there may have been
grounds to speculate in 1981 that tertiary recovery
would eventually become economically viable for
large offshore fields, today's lower oil prices suggest
that this will be unlikely during the next few years.
The Cambay Basin provides yet another example of
problems with Indian reserves data. In 1983, Indian
claims of proved and indicated balance recoverable
reserves in the basin were increased by 71 percent
above the 1982 figure of 385 million barrels to 658
million barrels. This large, one-time revision in re-
serves-little new oil was actually discovered-proba-
bly was made to win World Bank support for the
planned Cambay Basin Petroleum Project. More than
half of the projected 30,000 b/d peak incremental
production associated with the project is to come from
enhanced recovery in primarily heavy oilfields. The
problems India will have in applying and mastering
FOR techniques, in addition to normal economic and
technical risks associated with the project, suggest
that most of the increase in claimed reserves probably
cannot be exploited at today's prices.
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Appendix B
Contractor's Methodology
for Forecasting Production
Onshore
The contractor's forecast of onshore oil production is
based on an analysis of historical discovery indexes,
drilling rates, and reserves-to-production (R-P) ratios
because there are virtually no data available on
India's onshore fields except what was published
decades ago while the industry was still in private
hands. India is one of a handful of major oil-produc-
ing countries-the others are members of the Organi-
zation of Arab Petroleum Exporting Countries-
which refuses to provide field production statistics to
the Oil and Gas Journal for its annual survey of
worldwide production. The resource level the contrac-
tor used was the USGS's most likely level of remain-
ing recoverable reserves in currently producing basins
and undiscovered recoverable reserves in virgin terri-
tories.
The contractor's starting point for forecasting onshore
production was to compute a discovery index (DI) for
onshore India based on a methodology developed by
L. F. Ivanhoe in his study of world oil discoveries.
Exploration drilling data were pieced together from
various sources and compared with increments to
reserves. The data yielded a DI for India for the
decade of the 1970s of 127 barrels (bbl) discovered per
foot of exploration drilling. This compares with a DI
of about 3,100 bbl/ft for the less developed countries
as a group during the same period, indicating the
relatively low "prospectivity" of onshore India. Al-
though Ivanhoe found a consistent pattern of about a
7-percent annual decline in discovery indexes world-
wide, the contractor used the DI for the decade of the
1970s without modification along with estimated ex-
ploration drilling capability to forecast new discover-
ies through 1995, thus giving India the benefit of the
doubt in future oil discoveries.
The contractor then looked at R-P ratios based on
reported data and also created a smoothed time series
of reserves using drilling data and discovery indexes.
From the reported and smoothed data series, it ap-
pears that India's R-P ratio is not likely to fall much
below 15, higher than ratios of around 10 achieved in
developed countries with mature producing basins,
but not unexpected because of the inefficiency of
Indian operations.
The R-P of 15 was used to estimate production
annually through 1995 based on reserves estimates
unconstrained by any limit to undiscovered recover-
able reserves and made from drilling projections and
the discovery index. This is the maximum feasible
scenario depicted in figure 10. Output from currently
producing basins was projected by limiting available
reserves to proved reserves plus the amounts given as
the most likely undiscovered recoverable oil by the
USGS. The curve in figure 10 identified as "most
likely" represents a similar procedure using the
USGS estimates of most likely undiscovered recover-
able reserves from new basins plus remaining recover-
able reserves in currently producing basins.
Offshore
The contractor assumed offshore reserves of 2.33
billion barrels and a peak R-P ratio of about 15. This
is more realistic than the peak ratio of 17.33 implicit
in a World Bank forecast of India's reserves, but
perhaps still too high considering experience in other
offshore fields and the urgency with which India has
pursued Bombay High field development. If the peak
R-P ratio were 12, probably an average figure for
North Sea development, reserves would be about 1.8
billion barrels.
Thus, the government's production profile calling for
plateau production of about 350,000 b/d, which im-
plies reserves of about 2.2 billion barrels, with a four-
year plateau period and an empirically estimated 13-
percent postplateau decline rate represents a
reasonable, perhaps moderately optimistic, scenario
falling between potential high and low reserves esti-
mates. The peak R-P ratio associated with this sce-
nario is about 14.6. It is unlikely that actual produc-
tion will depart from the forecasted contractor
scenario by more than 10 percent in any given year
even if ONGC attempts to hold Bombay High pro-
duction at or near its peak level as long as possible.
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Figure 17
Main Indian Sedimentary Basins
NEW DELHI*
Boundary representation is
not necessarily authoritative.
Northern
Assn,m
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Appendix C
The Geology and Potential
of India's Major Basins
Assam, in northeastern India, produced all of India's
indigenous oil and gas before 1960. By FY 1983,
Assam accounted for only 19 percent of the country's
oil and 33 percent of its gas because of production
from new discoveries in western India. According to
the Indian Ministry of Petroleum, Assam has 20
percent of the nation's proved and probable recover-
able oil reserves and 16 percent of the gas.
The first commercial oil deposits in India were discov-
ered in 1890 at Digboi in Assam. Another major oil
deposit also was discovered in Assam at Nahorkatiya
in 1953. In addition, according to USGS, four or five
fair discoveries and an equal number of smaller
discoveries have been made.
The two major existing fields in Assam are at Digboi
and Nahorkatiya. The producing zones at Nahorka-
tiya are thicker than at Digboi but irregular in
thickness and area distribution, according to the
USGS. Effective thicknesses range from 30 to 210
meters and average 60 meters. The oil is waxy and
low in sulfur and generally has a high gravity.
Production in Assam has increased steadily from less
than 10,000 b/d in 1960 to current levels of about
100,000 b/d. Output was temporarily reduced by
more than one-half in 1980 when sectarian violence
caused production problems.
The contractor expects a slow decline in production in
the Assam basin over the next decade. Most of the
production from Assam, although in declining
amounts, will continue to come from the Nahorkatiya
field because almost half of the reserves in the Assam
basin reside there, according to USGS, and because
the smaller Digboi field is approaching old age.
Exploration and Production
The USGS estimates exploration in the Assam basin
about 80-percent complete. India has drilled 174
exploratory wells in the basin and an additional 205
The contractor believes the Indian Government has
assigned a lower priority to exploration in Assam than
to western India, especially the Bombay offshore
region. According to Oil India Ltd., 70 exploration
wells are planned in Assam over a 10-year period,
four more than the pace of the past but slow com-
pared with other areas in the world, even mature
provinces.
Production at Digboi is from 24 separate sands. Some
of the thicker oils are presently unrecoverable, accord-
ing to ONGC. Oil is produced primarily by dissolved
gas, pressure, and some water and natural gas drives.
Experiments with waterfloods were generally disap-
pointing, according to ONGC.
The Nahorkatiya field, 40 kilometers southwest of
Digboi, is quite different. Wells are deeper, with
greater spacing and greater per-well production. This
is apparently due to the relative youth of the field,
compared with Digboi, and the more modern produc-
tion practices that have been followed at Nahorka-
tiya. Irregular formation characteristics and pervasive
faulting require careful attention to reservoir charac-
terization and development. More than 140 wells have
been drilled. Production strategy is designed to pro-
long primary recovery and to blend the crude pro-
duced to meet refinery needs.
Wells at Nahorkatiya are 2,700 to 3,000 meters deep,
but drilling is less difficult than at Digboi, with
overall drilling rates exceeding 300 meters per day.
Controlled directional drilling has been successful to
locations under the Dihang River
A few other smaller fields have been discovered,
including Kusigan, 25 kilometers southwest of Digboi;
Moran, 40 kilometers west-southwest of Nahorkatiya;
Lakwa, 20 kilometers south-southwest of Moran;
Rudrasagar, 40 kilometers southwest of Moran; and
Geleki, 25 kilometers southeast of Rudrasagar.
development wells.
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Economic and Technical Constraints
Lack of available large prospects, except possibly in
the hostile environment of the neighboring Bay of
Bengal, is the major constraint to materially increas-
ing production from the area. Lack of suitable seismic
reflectors makes identifying reserves in subtle geologi-
cal formations difficult, and the complex geological
formation is likewise extremely difficult to explore,
drill, and develop. Attempts at FOR are under way
but have not been notably successful because of the
viscous, waxy quality of the oil and the heterogeneous
nature of the reservoirs.
Potential Reserves
The Indian Government estimated Assam's proved
and probable recoverable reserves at 708 million
barrels (bbl) in 1983; the USGS estimated recoverable
reserves (1984) at 750 million bbl, of which nearly
half (338 million bbl) are at Nahorkatiya. These
estimates may be somewhat inflated by overly opti-
mistic recovery factors.
The contractor concluded that well over 90 percent of
the recoverable oil in the Assam basin has already
been found. The small spread in the estimates of
undiscovered oil in the two USGS cases with the
highest probability points to the advanced state of
exploration in the district.
The Cambay gasfield-a major source of natural gas
for India-was discovered in 1958. Commercial oil
production from the Cambay Basin began in Septem-
ber 1961, following the discovery of the Anklesvar
field, the largest onshore field in India. The Cambay
Basin contains more reserves of oil and gas than the
Assam oil province, but
reserves are much smaller than those in the offshore
Bombay High area. Thin reservoirs and the small size
of structures limit the amount of additional oil and
gas that are likely to be found in the basin, in the
contractor's judgment
Government statistics indicate that the basin produces
about 14 percent of the domestic oil and 13 percent of
the natural gas in India. Anklesvar contains about
half of the Cambay Basin's reserves.
The World Bank evaluation of Cambay Basin fields
shows that the extreme variations in the main charac-
teristics reflect differences between the gassy high-
gravity fields in the south and the heavy oilfields in
the north.
Exploration and Production
The ONGC considers Cambay Basin to be one of the
best explored basins of the country. According to the
World Bank, through 1982, 697 exploratory tests
were drilled on 134 of the identified oil and gas
prospects. The surface mapping of the basin was
essentially completed by 1983. In addition, 58 percent
of the basin has been covered by gravity and magnetic
surveys, 66 percent by seismic survey, and 85 shallow
test holes have been drilled. The USGS considers
exploration in the Cambay Basin about 80-percent
complete. The large portion of the area already
explored supports the contractor's estimate that major
new quantities of oil and gas are unlikely to be found.
Offshore results in and near the southern end of the
Gulf of Cambay have been disappointing, including
dry holes drilled by a US company in the Saurashtra
block. The contractor believes that, because of unfa-
vorable geology in the area, the rest of the Gulf and
the shallow near-shore waters are not especially at-
tractive.
Oils in the Cambay Basin are reported to be generally
very waxy. The heavier oils probably resulted from
the degradation of original lighter oils by bacteria or
by oxidation by ground waters. Heavy oils are more
common in the shallower fields and in the northern
part of the basin. Exploration and development have
been aimed toward the light oils, leaving the heavy
oilfields in the northern part of the basin relatively
undeveloped, pending decisions to attempt more ex-
pensive heavy oil recovery methods.
The Anklesvar field covers about 26 square kilome-
ters. The World Bank reported that cumulative pro-
duction through August 1983 was about 370 million
bbl; current production is about 30,000 b/d, down
from 60,000 b/d in 1968. Oil is produced from 11
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sandstone zones at an average depth of about 1,100
kilometers. About two-thirds of the production comes
from three reservoirs near the top of the producing
zone. Remaining recoverable reserves are expected to
be about 72 million barrels, or about six and one-half
years of production at the current rate.
The Anklesvar reservoirs have good natural water
pressure to assist in production. Since oil and water
mobility is almost equal in the reservoir, the World
Bank projects ultimate recovery at an exceptionally
optimistic 53 percent of the original oil in place.
Water injection was started in 1963, and water
produced with the oil averages about 40 percent of the
total. In 1984, of 196 production wells that had been
drilled, 90 produced oil, seven produced gas, 15 were
watered out, and 84 awaited workover and installation
of artificial lift. In addition, there were 29 injection
wells used to inject water to stimulate production, and
21 other wells had been abandoned. The contractor
believes there is little chance of increasing reserves at
Anklesvar or of even reversing the production decline
because most of the areas have been thoroughly
tested.
The Cambay field has two oil- and gas-bearing zones,
an upper gas zone at 1,600 meters and a lower
undeveloped tight oil zone at 2,000 meters. The
World Bank reports that about half (53 billion cf) of
the original recoverable gas reserves have not been
extracted. Production has been declining, but new
drilling is expected to increase gas production some-
what. The Bank reports that, of 55 gas wells that have
been drilled, 20 have been abandoned because of
water encroachment, another 10 will be abandoned by
this year, and the rest will probably have to be
abandoned within six to seven years.
Because the light oilfields are relatively small and
have little prospects for expansion, the heavy oilfields
of Santhal, Balol, and Lanwa probably present the
only possibility for increasing output. Schemes for
FOR have been proposed to increase substantially the
production and ultimate recovery from these fields.
Only Santhal of the heavy oilfields, with 41 producing
wells, has been developed to any extent; production
there is about 4,800 b/d. A plan to drill 44 wells in
the northern section of the field would create another
4,900 b/d of capacity, according to the World Bank.
Economic and Technical Constraints
Physical constraints such as small and widely distrib-
uted fields, geological problems, and a low hydrocar-
bon content of the oil and gas fields reduce the
promise of the Cambay Basin. The large number of
small fields makes logistics, such as gathering line
systems and treatment facilities, more expensive and
makes it more difficult to achieve acceptable efficien-
cy. Gas collection from the large number of small
fields will also be difficult. High reservoir permeabili-
ties and active water drives make water encroachment
a problem, and this is worsened by irregular reservoir
configurations. Pressures in the geologic structures
require good engineering and special precautions in
drilling and production. There is a risk of formation
damage in low-pressure fields such as Cambay and
blowouts in high-pressure reservoirs such as Ankles-
var.
ONGC's field
operations in the Cambay Basin are plagued by
serious problems. The company uses obsolete and
wornout equipment and faces a serious shortage of
rigs to rehabilitate wells and install pumping equip-
ment. The increased use of pumps needed for water
injection and for production will require more electric
power than is now available. The fields also require
improved oil well cements and cementing practices
and better drilling muds, mud engineering, and mud
testing equipment to deal with difficult strata and
pressures.
About 10 percent of the original oil in place in the
basin is estimated to be heavy (that is, gravity below
18, API). Primary production of the heavy oils is
expected to be only about 5 percent of the oil in place,
and enhanced recovery will be needed to economically
justify producing the heavy oilfields. Recoverable
heavy oil may total 4.5 million bbl in primary produc-
tion and 18 million bbl with enhanced recovery. Total
basinwide recoverable heavy oil is thus about equal to
the amounts recoverable in some of the smaller light
oilfields.
State-of-the-art enhanced production operations-
such as massive hydraulic fracturing, polymer treat-
ments, and in situ combustion-will be needed to
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produce the heavy oils and to maximize production
from the light oilfields. These sophisticated and high-
cost techniques are not being used in India because of
lack of equipment and inadequate indigenous techni-
cal expertise.
Potential Reserves
The resource potential of the Cambay Basin varies
greatly depending on the proportion of the original oil
and gas in place that is assumed to be recoverable.
Estimates vary from as low as 5 percent in the heavy
oilfields to as much as 53 percent in the light oil-
bearing Anklesvar field. The World Bank staff uses a
basin average of 28-percent recovery of the original
oil and gas in place, which the contractor believes is
probably on the optimistic side.
Industry studies show that, worldwide, 65 to 80
percent of the ultimately recoverable reserves in any
basin are in the five largest fields. An optimistic view,
assuming that 65 percent of the reserves have already
been found in the five fields, would yield 1,092 million
bbl of original recoverable reserves. Since 421 million
bbl have already been produced, 671 million bbl
discovered and undiscovered remain. By comparison,
estimated proved reserves of 500 million bbl plus the
USGS "most likely" estimate of undiscovered oil
equal 650 million bbl.
The contractor estimates that 80 percent of the basin
reserve has already been discovered in the five largest
fields. On the basis of this estimate and the mature
stage of exploration, the contractor believes that only
small amounts of additional oil will be found in the
Cambay Basin.
Bombay Offshore Region
The Bombay offshore basin is the only basin on the
continental shelf of India that has proved and eco-
nomically viable production of oil and gas. The con-
tractor estimates that production in the Bombay
offshore area peaked at about 420,000 to 430,000 b/d
in late 1984, and production is now declining. Two of
the 10 marginal fields that India has discovered in the
area are producing small quantities of oil. The con-
tractor believes that ONGC's experience with devel-
oping these two small fields has dissuaded it from
proceeding with development of the remaining eight.
Even if development of all eight remaining fields were
to begin immediately, the contractor believes the
decline in offshore production could not be arrested.
In addition, the contractor does not believe new
discoveries made in the area will offset the decline.
Exploration and Production
The Bombay High field is the only truly significant
find in over 20 years of exploration of India's offshore
areas. The contractor estimated original oil in place of
about 7.5 billion barrels. The structure was discovered
by a Soviet reflection seismic survey in 1964, detailed
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The contractor used the petroleum industry measure-
ment that the maximum annual production rate from
a field should be 1 to 2 percent of original oil in place.
Considering the intensity of production activity at the
Bombay High field, it is reasonable to expect the
annual production rate to peak at 2 percent of original
oil in place. The contractor's estimate of peak produc-
tion rate of 410,000 b/d at Bombay High is equiva-
lent to 2 percent of the estimated original oil in place
of 7.5 billion barrels.
The announcement by ONGC of plans to double the
number of platforms in the Bombay High field sub-
stantially reduced the contractor's uncertainty about
future production potential. The addition of new wells
resulting in reduced well spacing will allow ONGC to
cut back well flow rates, while maintaining planned
overall field production. The contractor believes that,
without this drilling program, ONGC will run a high
risk of premature water intrusion and potential col-
lapse of production rates. Neither ONGC nor the
Ministry of Petroleum can afford to take this risk.
Despite budget cutbacks, the contractor expects
ONGC to proceed with plans for the new drilling
program at Bombay High as its top priority.
The contractor believes India will be relatively suc-
cessful in recovering oil from the Bombay High field.
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factor of 31 percent-considerably higher than the
26 -percent factor estimated
The higher
recovery estimate is used by the contractor because of
production performance to date
contractor applied a recovery factor of 31 percent to
the estimated oil in place of 7.5 billion barrels,
ultimately recoverable reserves would then be about
2.33 billion barrels. In the absence of detailed field
performance and reservoir data, the contractor used
this estimate of field reserves as an input with other
known and estimated data for his forecast of offshore
production potential.
Outside of Bombay High, the South Bassein gasfield
is the largest structure in the area. South Bassein is
scheduled for initial production in late 1986, pending
completion of offshore facilities and a pipeline to
shore. The unusually thick section of overlying rock at
South Bassein forms a good gas-producing reservoir.
in addition to Bombay High and Bassein, the
best remaining offshore oil prospects in the area
include Panna, Heera, Ratna, and Bombay High East
(BHE). Oil production has started at Heera and
Ratna.
A US oil company abandoned its concession after
drilling three tests to over 3,000 meters in the Sau-
rashtra offshore area 80 to 100 kilometers northwest
of the Bombay High field. This is the only drilling by
a nongovernment agency in the offshore Bombay area
and the only such private tests in India in many years.
Economic and Technical Constraints
Most of the operating constraints of the offshore
Bombay area can be overcome with state-of-the-art
technology, although the five-month monsoon season
hampers offshore construction and pipelaying. The
high wax content and poor viscosity of the offshore
Bombay oil require special handling with heating, de-
emulsifiers, or dilution with lighter oils to transport it.
Production and operating costs are also high because
the reservoir is thin and covers a large area. Only four
wells can be placed on each platform in contrast to the
12 or more common in the North Sea, the US gulf
coast, and elsewhere.
is not warranted.
Potential Reserves
Altogether, 39 structures in the Bombay offshore area
have been explored by drilling. Some oil or gas was
found in 19 of the structures. Another 134 structures
have been delineated, according to ONGC records,
but all of the untested structures are small. Many
have only one-half to one-tenth of the area of the
small fields near the Bombay High field. The contrac-
tor believes ONGC has tested the best possibilities
and has been able to determine which structures have
promise. On the basis of experience to date, the
contractor believes that further drilling in other areas
in line with experience in other similar basins.
The "most likely" USGS estimate of undiscovered oil,
1 billion bbl, would indicate that a little more than
two-thirds of the recoverable oil in the offshore
Bombay area has already been discovered. The con-
tractor believes the USGS estimate may be unduly
optimistic on the basis of experience in similar basins
around the world. The estimate assumes that two-
thirds of the undiscovered hydrocarbons lie in the
Bombay High field and that they are probably 55
percent gas and 45 percent oil on a barrel of oil
equivalent basis. The contractor believes available
seismic information, the thin pay zones with variable
porosity, and the complex faulted structural settings
indicate that the conservative (95-percent probability)
USGS estimates that 90 percent of the oil and 85
percent of the gas have already been discovered in the
offshore Bombay area appear to be more realistic and
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The USGS report estimates exploration offshore
Bombay to be 55-percent complete, but available
seismic structure maps indicate that about 90 percent
of the area within structures large enough to contain
producible reserves has already been examined by
drilling.
One problem with the USGS estimating method is
that it extrapolates from known information, and, in
the case of the Indian west coast, the extrapolation is
from the best-known area, the offshore Bombay, and
the early discovered Bombay High. The Bombay
High field, however, is the only very large structure
offshore Bombay, according to available seismic
structural information. The dry holes drilled on many
promising structures and the small size of remaining
undrilled structures in the area indicate to the con-
tractor that the USGS's "most likely" estimates are
too high. In any case, development, if started now,
assuming a new find, will not mature into sustained
production until late in the century at the earliest.
India's ONGC has identified the Krishna-Godavari
Basin on the eastern side of India along the coast of
Andhra Pradesh as the most promising new area of
both onshore and offshore petroleum potential outside
the Bombay High. The World Bank agreed to loan
India $166 million, 30 percent of expected Krishna-
Godavari exploration costs over the four-year period
ending in 1986. In its staff appraisal of the project,
the World Bank indicated that intensive exploration
of the area presented significant technical challenges,
but that the Krishna-Godavari Basin was the only
basin in India with sufficient promise to justify accel-
erated exploration.
The contractor's findings suggest that the assessment
by India and the World Bank of the basin's potential
is overly optimistic. Exploration results to date strong-
ly suggest that the basin's highest potential zone is
beyond the edge of the continental shelf. Environmen-
tal conditions worse than those in the North Sea
probably will limit the economic viability of develop-
ing future discoveries in this area.
The Krishna-Godavari sedimentary basin covers
14,600 square kilometers on the eastern side of the
Indian peninsula. About 60 percent of it is on shore,
30 percent on the continental shelf, and 10 percent in
waters exceeding 200 meters in depth. The contractor
hypothesized that, although reserves could conceiv-
ably be large, much of the oil and gas will be found in
small and subtle traps, both structural and strati-
graphic.
In this type of basin, the largest structures are often
located in deep water and explored late in the search,
if at all. From a simplified structure map presented by
ONGC's chief geologist at the Offshore Technology
Conference in 1984, the contractor estimated that
more than 90 percent of the offshore area lies beyond
depths of 200 meters. International oil companies
showed no interest in bidding on deepwater tracts in
the Krishna-Godavari area during India's second
round of lease offerings in August 1982.
Exploration Results
Onshore exploration has established the presence of
gas, but commercial production has not yet begun.
Seismic surveys began in about 1974, and the first
well, Narasaput-1, was drilled in 1978. The lack of
announcements of commercial discoveries, develop-
ment plans, or production projections, in the contrac-
tor's judgment, means either that drilling continues to
be plagued with problems or that a World Bank
evaluation of the field's prospects was overly optimis-
tic. The contractor does not believe onshore gas
production in the area will achieve more than local
significance in the near term because no major mar-
kets are nearby.
Offshore drilling began in 1979. World Bank report-
ing called the liquid flow rates disappointing and
attributed them either to poor reservoir permeability
or to formation damage around the well bore. The
high gas flow rates in the two zones demonstrate good
reservoir permeability for gas. Other exploratory drill-
ing results have been disappointing.
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Economic and Technical Constraints
The Krishna-Godavari area is handicapped by severe
weather, strong currents, poor bottom conditions, a
steep continental slope, overpressured strata, and
small structure sizes. It is subject to severe storms five
months out of the year, and four of the seven wells
recently drilled in the area were abandoned prema-
turely because of excessive wave heights or currents.
These conditions seriously complicate the design and
installation of deepwater production facilities and
would probably preclude the use of early production
systems, sea-bottom well completions, and other cost-
reducing technologies now under development for
marginal fields. Exploration efforts thus far indicate
that production per well is not sufficient to economi-
cally justify offshore platforms.
Potential Reserves
Both onshore gas and offshore oil and gas at Krishna-
Godavari are expected to have only negligible impact
on Indian energy supplies. The USGS rates the
Krishna-Godavari Basin with a "most likely" undis-
covered recoverable reserve of 180 million barrels of
oil and 0.8 trillion cubic feet of natural gas, based
primarily on basin analogies and drilling data. At the
5-percent probability level, the basin was rated with
480 million barrels of oil and nearly 2 trillion cubic
feet of gas, about one-fifth that of the Bombay High
area. Relatively optimistic USGS estimates reflect
ultimate physically recoverable reserves with current
technology and do not take into account the adverse
environmental conditions in the Krishna-Godavari
area. The contractor believes that no economically
recoverable hydrocarbons will be produced off shore
in the foreseeable future and only negligible amounts
will be produced on shore.
The Kutch Basin is located on the northwest coast of
India, and no economic oil or gas has been found to
date. The contractor believes the region is not likely to
contribute major additions to India's oil and gas
supply
In addition to surface mapping, other surveys-gravi-
ty, magnetic, and seismic-have been conducted, and
11 shallow exploratory holes have been drilled. Two
onshore wells were dry, with no shows. An offshore
wildcat found oil and gas shows, but it was aban-
doned. No surface seeps are known; some gas has
been reported from shallow water wells.
Economic and Technical Constraints
The major constraints are the apparent paucity of
source beds and a relatively high temperature likely to
be encountered in drilling. It appears that the more
favorable prospects are at or beyond the continental
shelf in deeper water. Terrain features and difficult
geologic features make exploration difficult. Amphib-
ious equipment would be required for geophysical and
drilling operation because much of the area is low-
lying, muddy tidal lagoons and swamps.
The Resource
Estimates of potential oil and gas resources in the
Kutch Basin must be based on analogies with similar
or nearby areas. In 1983, ONGC estimated original
oil in place of 4 billion bbl. Applying a recovery factor
of 20 to 40 percent to that figure-the range of
recovery from most Indian oilfields-potential recov-
erable reserves would be 800 million to 1.6 billion bbl.
The USGS has, by extrapolation of Bombay shelf
conditions, estimated the "most likely" value for
undiscovered recoverable oil at 700 million bbl. Its
conservative 95-percent probability estimate is 300
million barrels. USGS estimates of Kutch Basin gas
are 4 trillion and 1.8 trillion cf for the same probabili-
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mates.
The contractor estimated Kutch potential on the basis
of a combination of offshore Bombay and Indus Basin
conditions. Although the contractor believes Kutch
conditions at this time appear closer to Indus than to
Bombay, in the absence of other evidence he estimat-
ed 215 million to 290 million bbl of oil reserves in the
Kutch Basin.
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Other areas or basins have been explored only lightly,
but the contractor judges that the prospects are slim
for significant finds. The USGS estimates that the
most likely ultimate oil resources, none of which are
proved to date, in these other areas amount to about
one-eighth of the country's total.
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