AZERBAIJAN – ENERGY BASE
APS Review
Downstream Trends
July 12, 2004
v62, i2, p0
Azerbaijan is positioning itself to become a major
player in the energy world during this century. In the
early 1990s the country emerged from the Soviet era
with a teetering economy, a shrinking energy base,
environmental degradation and a conflict with
neighbouring Armenia. The recession ended in late
1995, but it was only in 1999 that economic recovery
began to accelerate.
Azerbaijan is rich in natural resources. It has a wide
range of minerals, including iron, aluminium, zinc,
copper, arsenic, molybdenum, marble and fire clay.
Scanty reserves of gold in the Armenian-occupied
Kelbajar region has been extracted by Armenians. Azeri
reserves of oil and gas are more than enough to meet
domestic demand in the long-term (see OMT & Gas Market
Trends of this week). The country is rich in gas
hydrates, which will eventually become a clean source
of energy and an alternative to hydrocarbons.
The economy faced a negative fallout resulting from
the collapse of the Soviet Union in 1991, when
Azerbaijan proclaimed independence. In the subsequent
years there was severe internal turmoil as pro- and
anti-Moscow groups fought for power in the country,
while a war was going on for control of the
predominantly Armenian enclave of Nagorno-Karabakh.
The situation began to stabilise after President
Gaidar Aliyev assumed power in June 1993.
Hyper-inflation has since been brought under control.
The Azeri currency, called manat, is relatively stable
and the country’s GDP has been rising since 1996 after
falling by two-thirds since 1989.
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APS Review Downstream Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – The Local Market.
Full Text: COPYRIGHT 2004 Input Solutions
The energy base of Azerbaijan has been shrinking
steadily since 1990. In each of 1989 and 1990, the
country’s energy consumption used to average 22.9
million tons/year of oil equivalent. This has dropped
to 19.1m t/yoe in 1992 and to 11.2m t/yoe in 2002. In
2004 consumption is expected to be higher but still
way below the 1992 figure.
Azerbaijan’s energy consumption mix comprises oil,
natural gas and hydro-power. Theoretically, it is one
of the most gasified countries in the FSU, as a result
of heavy investment during the Soviet era. Its gas
transmission and distribution network has the capacity
to cover 80% of the population of more than 8m, of
which 2.5m are in the capital Baku.
However, the country has suffered from gas shortages
which hit after the collapse of the Soviet Union. This
year, as in 2003, it is importing 4.5 BCM of gas under
contracts with Gazprom, Itera, and TransNafta. With
Azerbaijan producing 5.2-5.7 BCM/year, the bulk from
Socar’s fields, the country’s gas consumption in 2004
is expected to amount to 9.9-10 BCM. This compares
with 9.2 BCM in 2003, 7.9 BCM in 2002, 7.8 BCM in
2001, 5.4 BCM in 2000, 15.1 BCM in 1991 and 15.8 BCM
in 1990.
Oil consumption in Azerbaijan reached a low point of
73,000 b/d in 2002, compared to a peak of 171,000 b/d
in 1990. It fell gradually in the subsequent years to
reach 140,000 b/d in 1995, 124,000 b/d in 2000 and
about 74,000 b/d in 2001. The country has two oil
refineries in Baku with a combined capacity of 442,000
b/d. Until a few years ago, Azerbaijan used to be the
only net exporter of refined products in the Central
Asian region.
The oil retail business is controlled by the state
company Azpetrol, which was established in 1997. Its
network of filling stations, built in 1997-99, cover
the whole country and are located 50 km away from one
another. Each filling station offers fast food and
beverages, spare parts and auto-care products as well
as auto-repair services.
Azpetrol’s auto-service stations, which are fairly
well equipped, are open 24 hours a day. Apart from
mogas produced by the local refineries, Azpetrol is
the distributor of Shell’s oil products, Goodyear
tires and Champion auto-parts and accessories. It has
a fleet of delivery vehicles. The company is also
involved in exporting oil products. It has built a
terminal for reloading of raw oil from sea tankers to
railroad containers.
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APS Review Downstream Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – The Gas Market.
Full Text: COPYRIGHT 2004 Input Solutions
The local market needs more than 15 BCM/year of
natural gas. The Baku government has prepared a
long-term plan for gas production and domestic use and
for the modernisation of the existing gas distribution
system. A part of the plan’s cost has been covered by
a grant of $425,000 received in the autumn of 1999
from the US Trade and Development Agency. This has
also covered a study on the construction of new gas
processing facilities in the country and on exporting
gas by pipeline to Turkey and European markets.
Statoil of Norway, a partner in major E&P ventures in
Azerbaijan, is operating Azerbaijan Gas Supply Co.
(AGSC). Formed in early 2003, AGSC manages gas sales,
contract administration and business development
matters. In addition, Statoil will be the commercial
operator for business development and administration
of the South Caucasus Pipeline Co. (SCPC), which will
be operated by BP. BP leads the Shah Deniz consortium
and operates development of the offshore Shah Deniz
gas/condensate field, the first phase of which will be
on stream in the first quarter of 2006.
SCPC will be supplying 1.5 BCF/day of Shah Deniz gas
to the domestic market, Georgia and Turkey. The
pipeline will be expanded to 3 BCF/day in 2007 (see
Gas Market Trends).
Azerbaijan’s marketed production of natural gas used
to average 14 BCM per annum during the Soviet era. Of
this, the country used to consume 11 BCM/year and 3
BCM/year used to be supplied to Armenia. The current
development of the Shah Deniz field, together with
other gas fields to be developed, would raise the
country’s marketed production of natural gas to more
than 30 BCM/year by 2010/15, with 50-60% of this to be
exported to Turkey and other markets.
Only Baku, Sumgait and some other parts of Azerbaijan
are consuming gas at present. These areas have often
encountered shortages, due to local supply disruptions
since the early 1990s. Among new projects to import
natural gas for the local market is a relatively short
pipeline to be built for Itera from Turkmenistan to
the Azeri border which is proposed to pass via Iran.
Before the Khomeini revolution of late 1978/early
1979, Iran used to export natural gas to Azerbaijan
through the IGAT-1 pipeline to Astara. Iranian
supplies were resumed later and in 1990, but for very
short periods. Now IGAT-1 is only being used to supply
Iran’s domestic market. Gas supplies by pipeline from
Turkmenistan to Azerbaijan and Armenia during the
Soviet era ended after the war over Nagorno-Karabakh
erupted in the late 1980s between the Azeris and the
Armenians. Azerbaijan stopped exporting its own gas to
Armenia after the war was escalated and the Soviet
Union collapsed in late 1991. Azerbaijan declared its
independence in 1991. It joined the Russian-led
Commonwealth of Independent States (CIS) after
President Aliyev assumed power in June 1993.
The existing Azeri gas network, built during the
Soviet era, comprises about 4,500 km of high pressure
transmission lines, seven compressor stations and more
than 31,000 km of medium and low pressure distribution
lines. This system is low-tech by Western standards
and has been in poor condition, with many commercial
and industrial consumers having no gas meters. Meters
installed during the Soviet era were not accurate.
Metering of household gas use has been non-existent.
To ease the problem of shortages, the state gas
utility Azerigaz has been slowly implementing a “gas
system rehabilitation project” financed 82% by the
International Development Association of the World
Bank under a $20.2m loan. The $24.6m project, approved
in 1996, was also to improve delivery and boost user
efficiency. Azerigaz has provided $4.4m of the
funding.
The four components of the project are metering,
cathodic protection (CP) system rehabilitation,
analytical equipment, and corporatisation support.
Restoration of CP systems has reduced the need for
spending on pipeline replacement. The CP part of the
project has concentrated on the Absheron peninsula,
where most of the gas is transported and used. About
2,700 km of pipelines serve the area, which has the
highest population density in the country.
The Power Sector: Azerbaijan’s total installed
capacity for power generation is about 5 gigawatts
(GW), consisting of eight thermal plants which supply
about 85% of the electricity, and five hydro-electric
stations. The thermal plants are based mostly on heavy
fuel oil, and natural gas is only used as a secondary
source for some plants. But the actual generating
capacity now is less than 4.5 GW, because of obsolete
facilities and lack of proper maintenance, and more
than 30% of the power produced is lost due to a bad
transmission system and some theft. If the maintenance
system is not improved, the usable capacity would drop
further, while domestic demand for power has been
rising rapidly since 1996.
There is an exchange of power supplies between
Azerbaijan and each of Russia, Georgia, Iran and
Turkey. Since 1994, imports from these countries have
overtaken exports by far. Azerbaijan still depends
heavily on the import of power plant equipment and
spare parts from Russia and Ukraine, as a result of
full integration with them during the Soviet era.
The efficiency and profitability of the state’s power
utility, AzerEnerji, have to be improved. The utility
is to be partly privatised along with Azerigaz. This
is under a plan adopted in 2000, after a series of
major power cuts, which called for three basic
changes: (1) new incentives and a campaign to attract
foreign investment into this sector, (2) creation of
an independent power regulator, and (3) privatising
the regional power networks.
The power sector has received priority in the
country’s development plan. Among projects now being
implemented in the sector is a gas-based Combined
Cycle Power Plant-II being built at Severnaya on the
outskirts of Baku. With a capacity of 400 MW, this is
the country’s first gas-fired CC plant. It will
replace Severnaya’s 150 MW oil-fired station and is
aimed to ensure stable power supply in the
metropolitan area, cut air pollution and curb emission
of toxic gases. The project has been financed partly
by a loan of Y18,332m ($172m) from Japan Bank for
International Cooperation (JBIC), granted at the “most
concessionary” interest rate of 0.75% for a 40-year
repayment period including a 10-year grace period. The
oil-fired plant has been upgraded and mostly rebuilt
by Mitsui and Mitsubishi Heavy Industries (MHI) under
a contract with AzerEnerji.
The Baku Thermal Power Plant has been revamped and
expanded by ABB and Alstom under turnkey contracts
signed in early 1999 and late 2000, respectively. This
now has two new gas turbine cogeneration units with a
combined capacity of 110 MW and 400 tons per hour of
steam. Completed in 2001, it supplies heat and power
to the Baku refineries, other industrial customers and
households in the capital.
Hydro-power generating capacity available in
Azerbaijan now is limited to about 500,000 tons/year
of oil equivalent, compared to 400,000 t/yoe in
1991-95.
AzerEnerji has received two sovereign loans from the
European Bank for Reconstruction and Development
(EBRD) worth $60m for two projects: (1) to help
complete the Yenikend hydro-power plant on the Kura
River, which will enable Baku to raise fuel oil
exports and reduce the amount of gas needed for this
sector; and (2) to develop the legal and regulatory
frameworks for the sector, raise hydro-power
generating capacity and improve Azerenerji’s
management and monitoring systems.
The EBRD loans and aid from other multilateral
agencies, including the Islamic Development Bank, were
to help Azerenerji acquire computers, modern
communications equipment, electric metres and spare
parts. They were also to help replace three generators
at the Mingechaur hydro-power plant on the Kura River
to reduce pollution in that area. Sumitomo Corp. is
installing a wind-power plant for Azerenergy on the
Absheron Peninsula where supply of wind is abundant.
In addition, EBRD is helping in a programme to
privatise Bages, the major power distributor, and the
distribution network of the Baku Power Co.
However, both Azerigas and AzerEnergi are heavily
indebted to their fuel suppliers including Socar. The
two companies are also owed considerable amounts by
domestic and industrial customers.
Coal consumption in Azerbaijan between 1987 and 1991
amounted to about 100,000 t/yoe. But coal consumption
was stopped completely after the collapse of the
Soviet Union at the end of 1991. Unlike several other
former Soviet states, including Armenia, Azerbaijan
has no nuclear power generating capacity.
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APS Review Downstream Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – Refining & Petrochemicals.
Full Text: COPYRIGHT 2004 Input Solutions
Azerbaijan has a diversified downstream sector. It
includes two refineries with a total capacity of
442,000 b/d and 25 petrochemical plants, all built
during the Soviet era. Both refineries are located in
Baku. One is the Baku refinery, with a capacity of
230,000 b/d. The second is the Novo-Baku plant, with a
capacity of 212,000 b/d. The latter has a catalytic
cracker with a capacity of 34,400 b/d. The refineries
process a mix of Azeri, Russian and Kazakh crude oils;
but they are now operating at about 40% of their
capacity. Exports of diesel and jet fuel go to Iran.
Baku exports fuel oil and gasoil to Mediterranean
markets through the Black Sea.
The petrochemical sector is concentrated in the area
around Sumgait, close to Baku. There are also plants
in the capital, and in Neftechala south of Baku. All
the plants are based on Soviet technology, apart from
a polyethylene unit. This sector depends heavily on
feedstock imported from elsewhere in the FSU. The
functioning of plants was badly affected during the
early 1990s when most countries of Central Asia were
going through a tough political and economic
transition. One project that was launched during the
Gorbachev era in the 1980s, a polypropylene plant for
which the contract was awarded to Tecnimont of Italy,
was stalled for years because of financing
difficulties.
The plants are owned by AzeriChimia. They include a
300,000 t/y ethylene complex. This complex has
producing polyethylene, synthetic rubbers, latex,
propylene glycol, pyrolysis benzene and fractions of
butene, butylene and isobutylene. There is also an old
and heavily-polluted chlorine complex based on mercury
cells. Epichlorhydrin is produced at this site as
well.
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APS Review Downstream Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – The Economic Base.
Full Text: COPYRIGHT 2004 Input Solutions
Azerbaijan has a strategic location in the Caucasus, a
well educated and inexpensive workforce, a
dictatorship with a corrupt government, an inefficient
agricultural sector, and a vast base of natural
resources. Well aware of the country’s potential, the
government says its aim is to use oil and gas
development as a foundation from which to build up
Azerbaijan’s economic strengths.
After the collapse of the Soviet Union in 1991, the
Azeri economy was in a disastrous condition. The war
with Armenia and internal instability had made the
situation worse. Between 1991 and 1993, there was no
stable government. The assumption of power by
President Aliyev in June 1993 was the first step
towards political and economic stabilisation. But it
was not immediately possible for Aliyev’s leadership
to get the situation under control. Hyper-inflation
had reached 1,800% in 1994, for example.
The government then took the critical step in March
1995, with a decree by Aliyev to create a currency
market. Reform and aid deals were concluded with the
IMF, the World Bank, EBRD and other institutions. The
turning point for the Azeri economy in the post-cold
war era was in 1996.
GDP which had slumped by two-thirds from $21.8 bn
between 1989 and 1995, began to grow again.
Hyper-inflation was tamed to about 6.7%. In 1995
industrial production declined 21.4%, but in 1996 the
fall was brought down to 6.7%. The agricultural sector
showed a positive trend for the first time: production
declined 7% in 1995 but grew 3% in 1996. Foreign
capital began flowing into the country, mostly for oil
and gas projects, but also for smaller scale consumer
businesses in and around Baku. Since then, the GDP has
been growing by about 5% per annum. Inflation has come
down to 5% as well. For the first time since
Azerbaijan became independent, industrial production
has risen marginally in recent years. Due to inflows
of foreign capital, the currency has appreciated
against the US dollar.
However, Azerbaijan has proved to be a minefield for
many foreign firms trying to establish operations in
the country. A combination of a lack of transparency,
an inconsistent legal system and widespread corruption
have produced what one Westerner says is “an extremely
hostile place to invest”. Centralisation of real power
in the presidency – even relatively minor matters can
filter up to Aliyev – has led to avoidance of decision
making at lower governmental levels. Aliyev died in
December 2003, but he had been succeeded by his son
Ilham in October, when he was elected president (see
who’s who is DT & Gas Market Trends No. 3).
APS Review Gas Market Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – Socar’s Gas Production.
Full Text: COPYRIGHT 2004 Input Solutions
Marketed production of natural gas in Azerbaijan this
year is expected to be between 5.2-5.7 BCM, and this
is consumed locally. In addition, Azerbaijan is
importing this year 4.5 BCM from Gazprom, Itera and
TransNafta (see DT No. 1).
Marketed gas production has declined steadily in
recent years, from 8 BCM per annum in 1991, 7.4 BCM in
1992, 6.2 BCM in 1995, 5.2 BCM in 1998, 5.2 BCM in
2001, and 4.8 BCM in 2002. Socar produces the bulk,
about 5 BCM/year mostly from offshore fields, and the
rest is produced by AIOC.
The country’s demand for natural gas exceeds 15
BCM/year and the government can only import part of
the shortfall from neighbouring gas producing
countries (see Part 3 in next week’s Review).
Local demand for gas is expected to exceed 20 BCM per
annum in a few years. With a BP-led consortium
developing the giant Shah Deniz gas field for export
to Turkey and other European markets, gas production
in Azerbaijan is expected to exceed 30 BCM/year by
2010-15 and 50 BCM/year by 2020-25.
In most the PSAs signed since September 1994,
non-associated gas found by the foreign operators
belongs to Socar. One exception is the Shah Deniz PSA,
which has given the partners the right to all gas
found in that block.
BP, the operator, has found about 31 TCF of
recoverable gas and 1.7 bn barrels of condensate in
Shah Deniz. The costs of this field’s development and
related pipelines for export and the domestic market
will total about $3.2 bn, up from an earlier estimate
of $2.6 bn, with first gas for the local market and
exports now scheduled for the first quarter of 2006
(see below).
In the offshore Karabakh field, Pennzoil has found gas
instead of oil in the two wells it has drilled. But
the gas reserves discovered were not large enough to
justify the massive investment usually required,
because the area is far from existing infrastructure.
The negative result of the second well was reported in
early July 1998. Subsequently Pennzoil and its
partners abandoned the Karabakh venture (see Gas
Market Trends No. 1).
Socar is to develop non-associated gas reserves found
in early 1997 in a deep formation beneath an oil
reservoir on the north-western flank of the Azeri
field, which is operated by the BP-led AIOC. This was
discovered with AIOC’s delineation well at a depth of
3,450 metres. Socar has the right to all
non-associated gas in AIOC’s Guneshli, Chirag and
Azeri field areas.
In January 1998, Socar and Conoco (now ConocoPhillips)
signed a MoU for joint exploration of Azeri gas
resources, both onshore and offshore, and for other
gas projects. These include a $150m project to expand
Azerigaz’s 4.5 BCM/year gas processing plant of
Garadagskovo, south-west of Baku, and the production
of compressed gas (CNG).
In early 1998, Socar and Exxon (now ExxonMobil) agreed
to begin a joint study of the country’s gas resources,
of the local energy market and of the potential for
gas exports. An agreement for a similar study was
signed by Socar and Shell in March 1998. In July 1997,
Exxon and Socar had signed a PSA for the offshore
Nakhchivan block and later the US major got Blocks
D-3, D-9 and D-38 in the Baku archipelago adjacent to
Shah Deniz.
Azerigaz, a unit of Socar, is a monopoly in charge of
the country’s gas processing, transport, distribution
and storage. With 99 subsidiaries, it has an extensive
pipeline system. The group is being overhauled and
modernised with the help of Sofregaz, a unit of Gaz de
France, under a contract mostly financed by the World
Bank and a loan from the Japanese government. The
number of Azerigaz subsidiaries will be cut to 15 or
less.
Azerigaz is among state companies that would be
privatised and for this the World Bank would provide
$150m to help boost the group’s profitability.
Azerigaz has been hit financially due to low gas
selling prices and large payment arrears. It is trying
to restore and use some 4,000 km of idle gas
pipelines. These were laid decades ago by the Soviets
to carry Russian, Iranian and Turkmen gas to Armenia
and Georgia.
A joint venture was established with a Turkish
company, Global Trade, to revive the idle lines. The
aim is to restore the lines to withstand a pressure of
55 atmospheres. The JV would use most of the lines
eventually, and would rent a part to receive $1.5 to
$2.5 per MCM for gas pumped through.
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APS Review Gas Market Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – Azerbaijan International Operating Co.
Full Text: COPYRIGHT 2004 Input Solutions
AIOC, in which BP is the operator and consortium
leader, is currently producing around 155,000 b/d
offshore, up from 50,000 b/d in mid-1998. This should
reach 420,000 b/d or more in 2005.
AIOC this year is spending $2.45 bn on Phases 1 and 2
of the full-scale development of the
Azeri-Chiraq-Guneshli (ACG) complex on fields. Of
this, the capital expenditure amounts to $2.36 bn. The
remaining $9m covers operational expenses. In 2003 the
consortium spent $2.19 bn on the same development
programme.
AIOC had spent about $1 bn on an initial phase of its
programme, involving the Chirag field and its first
platform with a capacity of 130,000 b/d and related
facilities. The initial wells on this platform began
to flow crude oil on Nov. 7, 1997. The fourth
production well went on stream on May 25, 1998. Later
AIOC spent another $1 bn on further development work
and an export pipeline wich cost $590m. The pipeline
runs 917 km from Baku’s terminal and storage farm of
Sangachal (40 km south of Baku) to the Georgian Black
Sea port of Supsa and has a capacity of 100,000 b/d.
It has been on stream since April 1999.
Phase 1 of the full development for the main
production stream from Chirag, Azeri and the deep
formations of Guneshli fields will be ready in the
first quarter of 2005 to raise production to 420,000
b/d. This involves a permanent drilling platform to
handle 48 wells and a separate gas compressing
platform being built at the Azeri field. The new
platform will be linked to the onshore Sangachal
terminal by a new 30-inch marine oil pipeline.
Contracts worth $483m were awarded in December 2001 to
McDermott Caspian Contractors and Bouygues Offshore
for Phase 1. Saipem has installed a 12-slot main
drilling template on the seabed at the location where
the main drilling and living quarters platform will be
functioning. BP’s drilling of a first development well
at the same location was completed in May 2002 by the
semi-submersible rig Dede Gorgud. Another eight wells
are being drilled through the template, of which one
will be a water injector.
Under a $320m contract, McDermott is fabricating
platform topsides and installing marine pipelines for
the Azeri field. Bouygues got a $163m contract to
produce and load two platform jackets for the main
first phase production, drilling and living quarters
and for a new gas compression platform. Associated
piles for both structures, with a total of 45,000
tons, are also being built by Bouygues. The structures
are being built at the Baku fabrication yard of Socar
unit Shelfprojectstroy (SPS). BOS Shelf, a 50-50 JV of
SPC and Bouygues, operates the yard which has been
refurbished. Once built, the new facilities will be
installed by Bouygues on the Azeri field, 120 km
south-east of Baku. Entrepose is building new storage
tanks at Sangachal which will expand the terminal’s
capacity by 1m barrels.
Other components of the programme for Phase 1 awarded
in late 2002 and early 2003 include a 28-inch marine
gas pipeline, one for the topsides of a gas and water
injection platform, and one for the terminal main
tankage and dewpoint gas plant. In 2001 BP awarded
eight main contracts for offshore construction and
expansion of the Sangachal terminal.
The increase in crude oil production to more than
420,000 b/d in the first quarter of 2005 will coincide
with the coming on stream of the Baku-Ceyhan (BTC)
export pipeline. Phase 2, sanctioned in late 2002,
should raise oil production to more than 800,000 b/d
by 2007.
Another $3 bn will be spent on Phase 3. This should
raise AIOC’s crude oil production to more than 1m b/d
by 2009/2010.
New drilling also aims to double gas production at the
shallow Guneshli field to 400-500 MCM/year by 2006/07.
Total investment by AIOC could eventually reach $10
bn.
In June 2004 Aker Kvaerner’s unit Maritime Hydraulics
AS (MH) in Kristiansand, Norway, signed a MoU with
AIOC to deliver by the third quarter of 2005 complete
drilling installations for Phase 3. MH will also
provide training and long term operational support in
Baku.
MH’s supply will consist of a complete package
including pipe-handling equipment and drilling
machinery, as well as an advanced computerised control
system. The drilling facility will be fully automated
with the most advanced control system available in the
market today. It will meet the most demanding
requirements for safety, efficiency and working
environment, according to a company statement.
MH will be responsible for project supervision and
expertise for testing and start-up of the drilling
facilities. Project implementation and engineering
will start in October 2004 and will be carried out in
Kristiansand. (MH had previously signed major
contracts with BP for such projects as the ACG Central
Azeri, ACG West Azeri and ACG East Azeri systems, as
well as the Valhall project in the North Sea and the
Thunder Horse in the Gulf of Mexico).
AIOC’s aim is to recover a total of 5.4 bn barrels of
oil reserves at the ACG complex through the 30-year
life of its PSA with the Azeri government.
Work on the final 1m b/d pipeline to Ceyhan, Turkey’s
oil terminal on the Mediterranean, is progressing on
schedule and should be completed in early 2005 (see
Part 3 in next week’s Review).
AIOC sells its cost-recovery crude and most of equity
crude through the terminal of Supsa, in Georgia.
AIOC’s remaining share and Socar’s crudes are exported
through an old pipeline running north to Russia’s
Black Sea port of Novorossyisk. The crude from Chirag,
Azeri Blend, is a medium gravity sweet grade – 34.6o
API, with 0.15% sulphur and pour point of minus 3oC.
AIOC signed what was termed “the contract of the
century” with the Baku government in September 1994 to
develop the three fields under a $10 bn programme. The
30-year PSA was to prove and develop up to 5.4 bn
barrels of oil reserves.
BP, by far the biggest investor in Azerbaijan, leads
in five PSA ventures which are committed to spend a
total of up to $29 bn to find and develop up to 11.4
bn barrels of oil, 31 TCF of natural gas and 1.7 bn
barrels of condensate: AIOC’s, Shah Deniz, North
Absheron, Inam and Alov (see Gas Market Trends No. 1).
At first, BP’s work in Azerbaijan concentrated on
subsea inspection of an existing jacket on Chirag and
a feasibility study on early production from the
field. This was followed by an upgrade of an existing
rig. A 3D seismic work and site survey were done
together with an environmental study and preparations
for a logistics and supply base. By October 1995, the
old Chirag-1 platform was dismantled into nine modular
units and transported to the Shelfprojectstroy for
refurbishment 20 days ahead of schedule. The upgraded
platform was put in place by the autumn of 1996.
Drilling of three appraisal wells began in September
1996. In October of that year Saipem was contracted to
build a 182 km crude oil pipeline from Chirag-1 to the
Sangachal terminal and a 47 km gas line to link the
three fields. Work was completed in 1997. Start up of
production was delayed, however, mainly because of
problems with the section of the northern export
pipeline passing through Chechnya. Production
increased to the current 155,000 b/d level after the
coming on stream of the new export pipeline to Supsa.
Socar President Natig Aliyev has said AIOC’s annual
profits from the three fields would grow from $100m in
1999 to $2 bn in 2005 and $5 bn in 2007. AIOC has
benefited the Azeri economy considerably and has
sub-contracted work to over 90 local companies.
AIOC shares are held as follows: BP (34.14%), Unocal
(10.5%), Inpex (10% bought in 2003 from LUKoil), Socar
(10%), Statoil (8.56%), ExxonMobil (8%), TPAO (6.75%),
Pennzoil (4.82%), Itochu (3.92%), DeltaHess ACG
(2.08%), and DeltaHess Khazar (1.68%). DeltaHess, a
partnership between Amerada Hess and the Saudi oil
firm Delta, bought the 2.08% equity from Ramco Energy
of the UK in 2000.
LUKoil’s sale of its 10% equity to Inpex of Japan in
2003 has since become the subject of a tax dispute
between the Russian company and the Azeri government.
In March 2004, President Ilham Aliyev also weighed
into this by saying international experts should rule
whether LUKoil has to pay additional taxes resulting
from the equity sale. The Azeri Tax Ministry claims
LUKoil still owes as much as $200m in taxes resulting
from the sale. LUKoil sold its stake for about $1.35
bn.
President Aliyev was quoted as saying: “There is a
provision on the first production-sharing agreement
(PSA) signed in 1994 about assignment of the share
from one owner to a new owner. The way that it is put
in the contract is the peculiar way. You can treat it
as you like, therefore international expertise is
needed to clarify it”.
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APS Review Gas Market Trends, July 12, 2004 v62 i2 p0
AZERBAIJAN – The Shah Deniz Project.
Full Text: COPYRIGHT 2004 Input Solutions
By mid-2002, BP’s estimate of the cost of developing
the offshore Shah Deniz gas/condensate field and
building related pipelines for the domestic market and
for export had risen by $600m to $3.2 bn. This was an
example of problems being faced in exploiting gas
fields in virgin territory. The project had to be
delayed for years because of a lack of firm export
markets as Turkey had a severe economic crisis. The
Shah Deniz consortium had to proceed slowly until the
Turkish market became ready for the gas. As a result,
costs increased. But BP, the operator and consortium
leader for Shah Deniz, says the project is still
economically viable.
The field’s proven reserves are 31 TCF of natural gas
and 1.7 bn barrels of condensate. The Shah Deniz
partners sanctioned the project in late 2002. The
contract for Phase 1 development’s design,
engineering, procurement, assembly, installation, hook
up and project management assistance for a TPG 500
drilling and production platform – worth $300m – was
awarded in June 2003 to Technip of France. The
35,000-ton operating weight of the TPG 500 platform
which forms the centrepiece of the development will be
installed in a water depth of 345 feet (105m) and will
produce up to 900 MCF/day of gas and about 58,300 b/d
of condensate. It will be on stream in the third
quarter of 2006.
Keppel Fels of Singapore is fabricating the hull and
topsides. Kellogg Brown & Root (KBR) has the contract
for the design and procurement of the onshore
facilities to be built in the Sangachal terminal and
for the design of the offshore gas and condensate
pipelines to Sangachal. First gas deliveries to the
local market and for exports from Shah Deniz are
expected in the third quarter of 2006.
The shareholders in the Shah Deniz consortium are: BP
(25.5%), Statoil (25.5%), Total (10%), LukAgip (10%),
Socar (10%), NaftIran or Nico (10%) and TPAO (9%).
Nico acquired the 10% equity from OEIC, an affiliate
of state-owned National Iranian Oil Co. (NIOC).
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APS Review Oil Market Trends, July 12, 2004 v63 i2 p0
AZERBAIJAN – Part 2 – Rising Oil Production.
Full Text: COPYRIGHT 2004 Input Solutions
Baku, “the world’s oil capital” at the start of the
past century, hopes that its oil production will
exceed 1m b/d by 2010 and reach 2m b/d within the next
decade, compared to the current level of 350,000 b/d
which has risen by 170,000 b/d since 1997.
The country’s marketed production of natural gas will
rise considerably from 2006. It could reach 30
BCM/year by 2010/15 and probably 50 BCM/year by
2020/25, with Azerbaijan to become a major exporter of
natural gas.
Azerbaijan’s main challenge has been the securing of
export routes for oil and gas to help guarantee its
independence. Construction of a 1m b/d crude oil
pipeline from Baku to the Turkish terminal of Ceyhan
has progressed and the system should be on stream in
2005. A parallel pipeline is being built for the
export of Azeri natural gas to Georgia, Turkey, Greece
and other European markets (see Part 3 in next week’s
Review).
This country has the biggest number of international
consortia in the Caspian region to develop its main
oil and gas areas in the south. The first and largest
consortium, Azerbaijan International Operating Co.
(AIOC), is producing 155,000 b/d, up from 50,000 b/d
in mid-1998.
AIOC is aiming to raise its output to more than
400,000 b/d in 2005. This should reach 1m b/d or more
by 2010. The other main consortia are each aiming for
a large oil production system, with the Shah Deniz
group to become the biggest producer of natural in
Azerbaijan. (See the profiles of AIOC and the Shah
Deniz group in Gas Market Trends).
=================================================
APS Review Oil Market Trends, July 12, 2004 v63 i2 p0
AZERBAIJAN – Socar & Production Background.
Full Text: COPYRIGHT 2004 Input Solutions
The oldest oil producing region in the world,
Azerbaijan had an oil boom at the beginning of the
20th century and later served as a major refining
centre for the Soviet Union.
Oil production in Azerbaijan peaked at about 500,000
b/d during World War II. It fell significantly after
the 1950s as the Soviet Union redirected resources
elsewhere. All production used to come from onshore
fields.
Offshore exploration only started in the 1940s, when
the world’s first offshore well was drilled in the
Azeri part of the Caspian. The world’s first onshore
oil discovery was made in Azerbaijan in the 19th
century.
The country’s oil industry suffers from outdated
technology and poor planning, which have resulted in
under-production, waste and severe environmental
degradation. Due to shortages of funds, particularly
for drill pipe, exploration and development drilling
declined in the past three decades.
In September 1992, the state’s two companies,
Azerineft and Azneftkimiya, were merged to form the
State Oil Co of Azerbaijan Republic (Socar). Socar is
a huge, overstaffed company with more than 75,000
employees and with a long list of subsidiaries.
Socar produces oil and gas, runs the country’s two oil
refineries through a subsidiary, operates the pipeline
systems, and is in charge of oil exports and imports.
The energy ministry now handles the E&P deals with
foreign companies. The State Fuel and Energy Committee
controls local distribution of oil products and gas.
In early 2003, following a decree issued by then
President Geydar (or Heidar) Aliyev (who died last
December but was succeeded by his son Ilham who was
elected president in October), a programme to
restructure Socar was launched. One aim was to merge
Socar’s onshore and offshore production units. Under a
new charter for Socar, the company owns the oil it
produces.
Previously ownership was relinquished once the oil had
been transported on to processing facilities.
The restructuring has also seen three service
departments transferred to the Ministry for Economic
Development for further privatisation. By early
February 2003, 68 of Socar’s non-oil producing
businesses had been transferred to this ministry for
privatisation.
The political leadership decided not to privatise
Socar’s upstream business. This has annoyed potential
foreign investors, including one investment group
called Minaret. Headed by Czech businessman Viktor
Kozheni, Minaret has even accused Baku of deliberate
deception.
Socar has 78 fields in production. Of these, 17
offshore fields account for over 80% of its total
output. Total production by Socar and by
Socar-controlled JVs now average about 195,000 b/d.
Socar still lacks modern equipment and spare parts,
despite the fact that in Soviet days Azerbaijan used
to be the centre for the production of rigs and
various other field equipment. Socar’s production
system is grossly inefficient. It is said that crude
oil costs Socar between $15-17/barrel to produce
onshore.
There are almost 35 fields in offshore Azerbaijan. Of
these, 33 had been found by Soviet geologists since
the 1940s. More than 30 fields lie in the southern
region, mostly in waters of less than 200 metres.
The shallower formations of one field, Guneshli
located about 100 kilometres off the Azeri coast,
account for almost half of Socar’s oil production.
Guneshli is a giant. In the early 1990s, it was
producing about 125,000 b/d. Its deeper formations,
containing far more oil, are being developed by AIOC,
the main consortium led by BP.
Work on a joint venture to develop the shallow part of
Guneshli, to involve Total, has been delayed because
the French major has not accepted Socar’s PSA terms.
This project, called shallow-water Guneshli (SWG), had
previously been negotiated with Ramco of the UK and
Conoco (now ConocoPhillips) of the US.
Socar, which has devised a $1.7-1.9 bn programme for
SWG, insists that the PSA will only cover crude oil to
be produced on top of the company’s current average
output of almost 100,000 b/d, with this going to the
local refineries for the domestic market. Socar has
said SWG contained almost 1 bn barrels of oil.
Total was worried that SWG’s oil was migrating to the
deeper part of Guneshli which is being developed by
AIOC. Socar admits the PSA terms on offer for SWG are
not acceptable to foreign firms.
The SWG programme covers construction of a new
production platform in the northern part of the field,
where 12 existing rigs already operate, and
installation of a pumping station to prevent the
shallow oil reserves from moving down to AIOC’s
sector.
The oldest set of Socar’s offshore fields is in a
complex called Neft Dashlary (Oily Rocks). More than
170m tons of crude oil have been pumped from ND since
production began in 1948. Output peaked at about
170,000 b/d in the 1960s. It has since dropped to less
than 13,000 b/d. The complex’s importance has fallen
considerably.
Built in the middle of the Caspian Sea, Oily Rocks is
called “the eighth wonder of the world”. A “city” on
stilts, this has 150 kilometres of inter-linking
causeways built on pilings covering 40 sq km, of which
only a third is usable. It is 50 km from the nearest
land.
Oily Rocks boasts its own police force, dormitories,
hospital, gas-turbine power station and bakery. From
the air, the causeways seem to stretch to infinity,
but large chunks are falling off into the water, and
others are becoming submerged.
Socar executives hope a medium-sized Western oil
company will become interested in rehabilitating Oily
Rocks. While such company can extract oil to the last
drop, Socar would be spared the trouble of deciding
what to do with this inefficient complex.
The complex was offered to Western companies along
with four other offshore fields in its first
rehabilitation tender in June 1998. At the time, Socar
was hoping to attract $1.5-2 bn in total investments
for the five projects. But so far there have been no
takers. The Oily Rocks complex alone employs about
5,000 people.
All the big oil companies working in Azerbaijan looked
it over at one time or another. No one came close to
making an offer. Privately, Socar executives admit
that the complex – some of the pilings holding up the
roads should have fallen in the water 12 to 17 years
ago – may not last long enough to extract all the oil.
Most of the southern offshore fields are small and lie
at depths of 3-4 km below the water. The bigger ones
there lie at depths of 5 kilometres or more.
Exploration since independence in the complex geology
of the southern Caspian has suggested that major oil
and natural gas deposits lie at depths of between 6-8
kilometres.
It is estimated that more than 935 wells have been
drilled in the southern Caspian, including 180 at a
depth of 5 kilometres.
Of the many onshore oilfields, ten account for the
bulk of onshore production. But total onshore output
is averaging less than 30,000 b/d.
There are about 9,000 wells onshore and almost half of
them are idle. Many of the producing wells need
rehabilitation.
Some of the onshore fields are more than 120 years
old. Socar is still producing oil from Balakhany and
Sabunchy, which were discovered in 1871 less than 10
km north of Baku. They used to be the country’s giants
and have since yielded more than 330m tons of oil. Now
they are producing at the combined rate of 750,000
t/y.
Developing the onshore Kemalettin field is a JV
between Socar and Petoil of Turkey. The venture is
called PetZer. Its oil production fluctuates between
1,500-2,500 b/d. The field’s recoverable reserves in
recent years were estimated at about 50m barrels.
It was agreed between Petoil and Socar that, once the
field’s cumulative production reached 20,000 tons, the
crude oil would be transported to Turkey for refining.
This was to involve a complicated route using trucks
to Baku, a tanker sailing from the Caspian port to the
Volga-Don canal, and then to the Black Sea.
An alternative overland route the JV considered was to
be through Iran and then on to the refinery of Batman,
in south-eastern Turkey. Another alternative was to
truck the crude to Baku’s refinery and sell its yields
of oil products to Iran, Georgia and the Ukraine.
The largest onshore field is Muradhanly, having an
area of 3,100 sq km close to the Iranian border. But
it is only producing 3,500 tons/month. The field has
reserves estimated by Socar at between 6m and 18m
tons. The field was partly developed by the Soviets in
the 1960s.
Ramco Energy of Scotland in June 2001 pulled out of a
JV which was to rehabilitate and modernise the
developed section of the field. Ramco was also to
develop the other sections and undertake exploration
of deeper horizons. But it only drilled one well which
proved disappointing.
Muradhanly was later negotiated between Socar and
China’s state-owned company CNPC. Socar estimates the
field needs about $1 bn of investment.
The onshore fields of Kyursangy and Karabaghli, in the
Lower Kura Basin on the Absheron peninsula and 100 km
west of Baku, are being re-developed by the Salyan Oil
consortium consisting of Socar (50%) and CNPC (50%).
CNPC has bought the 20% stake of the US-Saudi
partnership of Amerada Hell and Delta (DeltaHess) and
taken over the operatorship from the latter.
Before selling its stake to CNPC, DeltaHess was is
producing about 6,100 b/d from the fields. Under the
original E&P deal for the Salyan project, it was
planned that a further development of the fields would
require about $900m. Socar then estimated the fields’
recoverable oil reserves at 100m tons (730m barrels).
CNPC joined the Salyan consortium in early 2002, when
it bought a 30% equity from the London-based European
Bank for Reconstruction and Development (EBRD). The
EBRD had inherited this from Frontera Resources of the
US in August 2001, after the latter was unable to
repay a $60m EBRD loan.
The Chinese company decided to buy the DeltaHess stake
in late 2002 after it became convinced that the Salyan
prospects were good. Socar then upgraded its estimate
of the recoverable oil reserves to more than 1 billion
barrels.
The Salyan group hopes to recover at least 25m tonnes
of crude oil in the initial phase of the development.
The fields were discovered in the early 1960s by the
Soviets. Some 600 wells have been drilled in two of
the fields (see background of this venture and its
output in Gas Market Trends No. 1).
Near these fields, Socar in early April 1999
discovered a gas-rich structure called Vandavan. Three
wells drilled into the structure tested between
500,000 and 1 MCM/day. After additional wells were
drilled through to end-1999, Socar geologists said the
field’s recoverable gas reserves were about 25 BCM.
They said there would be additional gas reservoirs in
that area.
On Feb. 1, 2002 Socar began a five-well delineation
programme to confirm oil and gas reserves at the
onshore Zira field, which was discovered in 1955 by
the Soviets. The field began producing oil in 1956 but
the output fell in the subsequent years and the
Soviets abandoned the structure. Socar on Feb. 1, 2002
spudded the first well.
Zira has two main reservoirs, the Kala and Podkirmaku.
Socar has said that each of these formations can
produce 400-600 b/d of 32o API oil, and that the
field’s remaining recoverable reserves were 7.5m
barrels of oil, about 35 BCF of gas and 100,000
barrels of condensate.
The onshore South-west Gobustan oilfields are being
developed by a JV of Socar (holding 20%) and the
British-Canadian Commonwealth Oil Refining (80%). The
PSA for this was signed on June 2, 1998 and under the
project Commonwealth Oil was to spend between
$700-800m. The fields’ reserves were estimated at 750m
barrels of oil and 900 BCF of gas.
On June 2, 1998, Socar signed with Agip a $2.5 bn PSA
for the Kurdashi offshore block with estimated
reserves of 100m tons. Agip holds 25% and is the
operator. Socar holds 50%, Japan’s Mitsui holds 15%,
and Turkish Petroleum (TPAO) has 5%. Repsol holds the
remaining 5%. Among several other onshore fields to be
rehabilitated in partnership with foreign companies
are Bibi Eybat and Buzovny-Mashtaga, which have been
on offer since 1997.
US explorer Moncrief in July 2000 began work on the
onshore Padar-Harami block in the Kura Valley, where
oil reserves have been estimated at 1 bn barrels.
Holding 80% under a PSA signed in 1999, with Socar
having 20%, Moncrief’s local unit Kura Valley
Development Co. has since evaluated the available
data.
Its programme called for three exploration wells to
indicate whether additional seismic is required. At
the exploration stage, investment was set at $50m. If
all goes well investment may reach $2 bn.
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APS Review Oil Market Trends, July 12, 2004 v63 i2 p0
AZERBAIJAN – Socar Improving Services.
Full Text: COPYRIGHT 2004 Input Solutions
Socar is developing its petroleum equipment and oil
service industries with the help of western companies.
It has a JV with McDermott of the US, MacShelf, which
builds deep-water platforms.
In May 2000 Socar signed a ten-year co-operation
agreement with PetroAlliance of the US for exploration
and development services both onshore and offshore.
Socar has since signed co-operation agreements with
several service companies specialised in a range of
upstream operations.
Socar has since since the early 1990s it wanted
co-operation agreements and JVs with foreign companies
to cover the widest range of upstream equipment and
services possible. Other projects include construction
of underwater pipelines and the reconstruction and
retrofitting of ships for use in drilling and laying
of marine pipelines.