REFINING CAPACITY: 441,808 B/CD
OIL PRODUCTION: 257,800 B/D
OIL RESERVES: 1.178 BILLION BBL
GAS RESERVES: 4.4 TCF
Azerbaijan's economy, fueled by investments in oil and gas, in 2000 extended a growth spurt that began in 1995. Gains of 5-7%/year were expected at least through 2005.
The country decided to suspend approval of new joint ventures and convert existing ones to production sharing agreements. Joint ventures required domestic sale of produced oil and had greater tax burdens than PSAs.
The foreign ministry opposed Iran's decision to award Royal Dutch/Shell and Lasmo a license to run seismic surveys in a Caspian area claimed by Azerbaijan. The Azeris planned to call a tender for D43, D44, and D74 blocks in the same area and prohibit Iranian participation in oil exploration projects in Azeri waters.
The country was trying to reform its power sector. It sought bids for 16 distribution networks but received bids for only four. Generating capacity in 2000 was 5 Gw. Azerbaijan had five hydroelectric plants, but more than 80% of its power came from eight thermal plants burning mostly resid (mazut). Shah Deniz, Chirag progress
One large development project and one discovery-appraisal hit stride in the Caspian Sea while operators let seismic contracts and flanged up production sharing agreements with Socar on numerous other blocks offshore and on land.
A BP group, saying it had already found enough gas on the Shah Deniz structure to justify a pipeline to Turkey, spudded its third well at Shah Deniz southeast of Bahar gas-condensate field in the Caspian.
The second well, 6 km south of the discovery well, flowed as much as 63 MMcfd of gas and 3,250 b/d of condensate from the Fasila Suite and 60 MMcfd and 3,100 b/d from Balakhany VII, with equipment restricting flow from both zones.
Gas reserves at Shah Deniz were estimated at 700 bcm after the testing of two wells. The third well stood to increase that estimate.
The group was drilling with the Istiglal semisubmersible, reported to have been the only rig in the Azeri Caspian equal to the task. A total of six wells were to be drilled.
Shah Deniz engineering work would involve installation of platforms, laying a subsea pipeline to shore, renovating and adding compressor capacity to an existing 490-km pipeline from the Baku area to the Georgian border, and laying a 280-km line across Georgia to Turkey.
The field is about 70 km southeast of Baku in 50-600 m of water.
Meanwhile, another BP group was building production from Chirag field in the supergiant Caspian Megastructure, which consists of Azeri and Chirag fields and the deepwater portion of Guneshli field.
The megastructure is 50-55 km long by 3-5 km wide.
Socar discovered Chirag field in 1984, and production began Nov. 7, 1997. BP was named operator beginning in June 1999. The group, known as Azerbaijan International Operating Co., by October 2000 had drilled 11 producing wells and 3 water injectors and had 1 well awaiting completion. Footage totaled 207,195 ft.
Some wells had flowed as much as 30,000 b/d of oil. Total production reached 75,000 b/d by yearend 1998 and 110,000 b/d by yearend 1999, and development drilling continued, said participant Exxon Mobil Corp. Capacity of the first platform was 115,000 b/d.
Output was to expand to 1 million b/d by 2010 from the initial platform, approximately centered on the megastructure. That $2 billion expansion project included a second, 48 slot platform, a 92 mile, 30 in. subsea pipeline, and expansion of the onshore terminal. The expansion depended on parallel progress of a suitable export pipeline alternative, Exxon Mobil said.
Exxon Mobil described the megastructure as one of the world's largest offshore fields, with reserves of 6 billion bbl of oil and nearly 6 tcf of gas.
The shallow-water part of Guneshli field produced more than half of Azerbaijan's oil output. Other Caspian activity
Operators were gearing up to conduct a wide array of other projects in the Caspian and onshore.
Agip Azerbaijan BV spudded Araz Deniz 1X on the Kur Dashi block 160 km south of Baku on Apr. 24, 2000. Projected TD for the first of three wells was 4,072 m. The 550 sq km block is in 10-700 m of water south of the Kura River delta and 45 km east of Lenkoran. Results were not available late in the year.
The Socar-led Japan Azerbaijan Oil Co. joint venture let a contract for collection and processing of shallow-water
3D seismic data over a Caspian Sea production-sharing agreement area that includes the Yanan Tava, Mugan Deniz, and Atasgah structures. The PSA is 80 km south of Baku.
The plan called for data acquisition around mud volcanoes in less than 5 m of water. The survey was the largest shallow-water survey so far in the Caspian.
An Exxon affiliate operating the Zafar-Mashal production sharing agreement let a contract for a 3D seismic survey in late 2000 on the 850 sq km area over the Zafar and Mashal structures in 1,800-2,900 ft of water 110 km southeast of Baku.
By late in the year, Exxon Mobil did not report on work during 2000 if any on other Caspian blocks in which it held interests. Those included Nakhchivan, Oguz, Lerik Deniz, and Alov (also called Araz-Alov-Sharg).
Caspian Geophysical, a Schlumberger-Socar joint venture, operated the Baki seismic vessel in the Caspian and in late 1999 took delivery of MV Gilavar, formerly Geco Gamma, refitted especially for work in the Caspian.
Shell E&P International acquired 25% of the BP-operated Inam license in March. Water is 30-100 m deep, and the first well was to spud in late 2000. The holders had acquired 538 sq km of 3D seismic data.
Russia's Lukoil was to proceed with at least one wildcat on the Yalama (D-222) block but probably not until 2003 because of rig delays and other factors. It was to upgrade its Shelf-7 semisubmersible to handle the job.
Geophysical data indicate that Yalama could hold 6 billion bbl of oil but that the structures are scattered and broken up. The block is in as much as 800 m of water 50 km off Azerbaijan's northernmost coast and south of oil discoveries off Russia's Dagestan Republic.
At 250 km north of Baku, the block is remote from infrastructure. Azerbaijani onshore
PSAs were signed for several land blocks, and the first joint venture onshore well was drilled during the year. Lack of pipeline capacity restricted production, however.
Ramco Energy PLC, Aberdeen, Scotland, set production casing on its first new well in giant Muradkhanli field, one of Azerbaijan's largest onshore fields. Muradkhanli, in the Kura basin 110 miles southwest of Baku, had produced about 20 million bbl of oil through 1997.
Ramco and Socar held equal interests in Muradkhanli, Jafarli, and Zardab fields under a production sharing agreement that covers the 565-sq-km Muradkhanli block.
Lukoil and Socar agreed to rehabilitate and develop Hovsanny and Zykh fields on the southern Absheron peninsula. The fields produced for decades and were making 1,760 b/d. Lukoil believed they still might contain as much as 20 million tonnes of recoverable crude.
A group led by Frontera Resources Corp., Houston, held 30% interest in 116,000 acres in Azerbaijan, including giant Kursange and Karabagli fields. Frontera said production more than doubled from the 2,800 b/d level when it entered the area in 1999. It expected a similar increase within a year or two.
Moncrief Oil International Inc., Fort Worth, was to spend $50 million in 3 years to explore and develop the 410 sq mile Padar concession 60 miles southwest of Baku. At least three wells were required.
Commonwealth Oil & Gas Co. Ltd. sold 11% of the exploration, development, and production sharing agreement for the Southwest Gobustan oil and gas concession to a unit of Oklahoma-based Sooner International Petroleum Co. Ltd. Sooner received an option to purchase a further 5%.
The venture was to rehabilitate an unspecified field that had 137 cased wells on nine structures that were shut in or abandoned. A further six structures were undrilled.
In late 1999 a group called Puma Energy Inc., Dallas, began negotiating with Socar for rehabilitation, exploration, development, and production agree-ments covering Balakhani, Sabunchi, and Ramani fields. Interests were to be determined. Upgrading refineries
Azerbaijan's refineries, both near Baku, have capacities of 203,000 b/d and 239,000 b/d, but runs in 2000 averaged only about 40% of the total because the plants were in disrepair.
Upgrades enabling the country to boost total capacity only to 260,000 b/d were to cost $600-700 million.
Japanese companies Nichimen Corp., Tokyo, and Chiyoda Corp., Yokohama, presented upgrade recommendations to the government in May 2000.
The rehabilitated plants probably would emphasize production of transport fuels and specialty lubricants rather than fuel oil as gas replaced fuel oil in the power sector.
The government hoped to build an 855 km, 60,000 b/d pipeline by 2010 to ship products destined for Europe from Baku to the Georgian Black Sea coast. Shipping Caspian output
In addition to the products pipeline, oil and gas pipeline project proposals advanced during the year.
An eight-company group signed a frame agreement for a 1 million b/d, 1,700 km, 42 in. line from Baku via Tbilisi, Georgia, to Ceyhan on the Turkish Mediterranean.
Called Main Export Pipeline, it was subject to a final decision that might not come until well into 2002.
BP unwrapped plans at midyear to export gas from Shah Deniz field to Turkey beginning as early as 2002. The plan competed with Turkmenistan's plan for a Trans-Caspian Gas Pipeline.
BP proposed to supply Turkey with 5 bcm/year of gas from the winter 2002-03 onward, for a first-stage period of 5 years. The investment was projected at $1.3 billion for that first stage. Deliveries could rise to 16 bcm/year in the second stage, with Turkey acting as both buyer and transit country.
Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001
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