Energy Research Group (UKRAINE)

UKRAINE

CAPITAL: KIEV
MONETARY UNIT: HRYVNIA
REFINING CAPACITY: 1,026,259 B/CD
OIL PRODUCTION: 47,700 B/D
OIL RESERVES: 395 MILLION BBL
GAS RESERVES: 39.6 TCF

The year 2000 began with the potential to have become Ukraine's first year of economic growth since it broke from the Soviet Union, said the US EIA.
From January through April 2000 the economy expanded by 5.5%, foreign trade was projected to increase by 1.7% on the calendar year, and GDP growth was forecast as high as 2% on the calendar year.
The energy sector was still considered to be in bad need of reform. Huge debts to Russia for gas and power and illegal diversions of Russian gas had strained relations and resulted in drastic action.
Russia imposed an oil blockade on Ukraine for several months in late 1999 and early 2000, and Ukraine refused to lower its tariff for oil transiting its territory towards the West. Kazakhstan began supplying about 25,000 b/d of oil to Ukraine, but high oil prices enticed some Russian exporters to sell elsewhere oil formerly shipped to Ukraine. Ukraine was seeking other gas suppliers.
Ukraine's parliament, wanting to turn the country into an attractive transit point for Caspian Sea oil, approved construction in 1995 of an 800,000 b/d terminal at Yuzhny near Odessa. The unbuilt terminal's cost estimate had grown to $1.3 billion from $790 million. Upstream developments
Ukraine wanted to stem declines in its oil and gas production, and higher commodity prices led to several agreements during the year.
Regal Petroleum Ltd., London, and M.L. Cass Petroleum Corp., Calgary, planned to merge and further develop three gas and condensate fields near Chernigiv in the Dnieper-Donets basin 200 km east of Kiev. The fields were producing 7 MMcfd from five wells and were certified with proved and probable reserves of 906 bcf of gas and 52.2 million bbl of condensate.
Conel, Romania's national electricity company, had agreed to take the gas. The firms were to deliver as much as 75 MMcfd of gas in summer and 140 MMcfd in winter.
EuroGas Inc. and ZahidUkrGeologia drilled Taihilivske-1, Ukraine's first coalbed methane well, to 830 m on a 150 sq km concession covering the Volyn coal field near the Polish border. EuroGas said the well found indications of gas from two coal seams and associated sandstones.
Ukrainian officials said they would soon begin developing what were considered to be vast gas resources along the shelf of the Black Sea and Sea of Azov.
Bellwether Exploration Co., Houston, acquired majority interest in Carpatsky Petroleum Inc. in December 1999 with rights to 1-2 tcf of gas in the Ukraine's largest gas basin. Bellwether said legal, financial, and operational issues prevented the project from being economically viable. The company considered the venture a long-term project.
Essex Resource Corp., Vancouver, decided not to exercise its option to acquire a 12% working interest in the Tatyanovskoe and Oktyabrskoe licenses in the Autonomous Republic of Crimea, Ukraine. Essex said it wanted to focus on its Hassi Bir Rekaiz play in Algeria. Processing activity
After several unsuccessful attempts, Ukraine began to auction stakes in its refineries.
Lukoil unit Luk Sintez Oil bought 25% more of the 56,000 b/d Odessa refinery through a stock swap valued at $2.5 million, bringing its stake to 76.9%. Luk Sintez paid about $6 million for 51.9%
of the refinery in 1999, promising to revamp it and supply it with 48,000 b/d of crude oil.
Tyumen Oil Co., Moscow, at midyear paid $9.76 million to acquire a 67.41% interest in the formerly state-owned 320,000 b/d Lisichansk (Linos) refinery in eastern Ukraine. The agreement would expand the lubricant marketing region of its partner Texaco Inc. to Ukraine.
Tyumen and Texaco expanded their relationship to include commodity risk management. They jointly marketed Texaco-branded imported lubricants and Tyumen and Texaco-branded lubricants produced and blended at the Ryazan refinery 120 miles southeast of Moscow.
Tyumen planned to modernize and expand the refinery, its first outside Russia, during 5 years. It planned to set up a sales and distribution network for Linos's products, including gasoline, diesel, fuel oil, polypropylene, ethylene, and other chemicals. It also was to sell lubricants in Ukraine through a joint venture with Texaco.
Gasoline marketing in western Ukraine was expected to benefit starting in late 2000 from a downstream alliance between Hungary's MOL Rt. and Slovakia's Slovnaft AS. Slovnaft was operating two service stations there and planned to construct more. Transportation
The government planned to end the state petroleum company's monopoly in gas purchases, transportation, and sales.
The government was working on a gas market concept under which the right to trade gas with all users in a region would be awarded in a tender and participants would have to produce property guarantees. Municipal and regional gas-transporting agencies as well as commercial companies were to be allowed to take part.
An official said that gas transportation would be unbundled from sales and that if a company providing gas failed to collect fees it would lose the right to sell gas in the particular region and, if necessary, be held accountable with its property.
The plan was a reaction to the state oil company's inability to organize an effective system of gas supplies and collection of fees for delivered gas.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (GEORGIA)

GEORGIA

CAPITAL: TBILISI
MONETARY UNIT: LARI
REFINING CAPACITY: 106,436 B/CD
OIL PRODUCTION: 2,000 B/D
OIL RESERVES: 35 MILLION BBL
GAS RESERVES: 300 BCF

Energy problems of several kinds challenged Georgia's emergence from the former Soviet bloc.
Chronic power shortages plagued the country, which in 2000 generated enough electric power to fill only about half of its estimated demand of 40-45 million kw-hr/day. Hydroelectric accounted for 80% of Georgian power generation. About 100 billion kw of potential hydro energy was untapped.
Georgia had minor oil and gas production and reserves but was taking steps to increase all categories. The country lies at a pipeline crossroads for the westward transportation of oil and gas from the resource-rich Caspian Sea region. And it was improving its refineries.
Georgian officials said a lack of funds for repairs and fuel for power stations caused the outages. President Eduard Shevardnadze promised that service would improve.
Georgia became independent with the 1991 collapse of the Soviet Union and suffered economic woes aggravated by civil unrest and conflicts with separatist rebels in two regions.
There were calls for the republic to connect its electrical grid to Russia's, but such a move would be politically awkward for the westward-looking Shevardnadze, who had tried to steer Georgia away from depending on its giant neighbor. Upstream developments
Georgia's state Saknavtobi (Georgian Oil) licensed blocks to several western joint ventures and was pursuing limited exploration.
Saknavtobi and the German company GWDF International were to sign an agreement establishing an oil prospecting partnership in late 2000. The project
also involved developing fields in western Georgia at Chaladidi, Supsa, and Shromisubani. The German company was to invest $3 million/year in exploration.
Georgia was to own 70% of any oil produced, while the German company would get 30%. Work was to start by yearend 2000.
Frontera Resources Corp., Houston, garnered a $50 million loan from European Bank for Reconstruction and Development (EBRD). It was the second phase of a $60 million package initiated in June for development of Kursange and Karabagli oil fields in Azerbaijan and Block 12 in eastern Georgia.
Frontera began operating in Georgia in the mid-1990s and moved into Azerbaijan in 1999, following the Kura basin play from eastern Georgia into offshore Azerbaijan. In the process, it helped assemble the largest onshore acreage position in the Caucasus region, more than 1.4 million acres.
Block 12 in eastern Georgia includes 1.3 million acres with seven known fields and numerous exploration prospects. Included is Taribani field, the first of Frontera's development projects, which contains gross unrisked reserves estimated at 1 billion bbl of oil equivalent.
Frontera had 100% of the foreign company operating interest in a production sharing agreement in partnership with Saknavtobi.
CanArgo Energy Corp., London, was attempting to rehabilitate and further develop Ninotsminda oil field 40 km east of Tbilisi.
Ninotsminda produces 41° gravity crude from Middle Eocene fractured volcanics at 2,600-3,000 m. It is 10 km west of Samgori, the Georgian field with highest cumulative production at 180 million bbl.
The field averaged 1,416 b/d in the first 9 months of 2000, of which CanArgo's share was 709 b/d. It made 5 MMcfd of gas, including 3.3 MMcfd to CanArgo. Some gas was flared.
The N97 exploratory well, aimed at gas postulated in Cretaceous at 4,000 m, unexpectedly discovered gas and oil in Sarmatian (Upper Miocene) and Upper Eocene at 1,960-2,100 m and had mechanical problems. TD was 2,249 m. The N98H well stabilized at 220 b/d and 750 Mcfd of gas on an 8 mm choke with 765 psi flowing tubing pressure from a 350 m horizontal leg in Middle Eocene.
Interruptions of power from the Georgian grid delayed field operations. CanArgo signed an agreement with AES Gardabani, a unit of AES Corp., Arlington, Va. AES Gardabani owned two units of the privatized Gardabani thermal power plant, and another AES Georgian unit owned the Tbilisi power grid. AES Gardabani was to participate and partly fund CanArgo's deep Cretaceous gas program at Ninotsminda. Processing activity
Georgia's hub location for crude oil transport helped it attract considerable foreign investor interest in its refining sector.
The country's two refineries are a 106,000 b/d plant at Batumi on the Black Sea coast and the 4,000 b/d Georgian American Oil Refinery at Sartichala east of Tbilisi.
The Sartichala refinery was idle from May 2000 after Georgia's Parliament banned imports of its feedstock, pyrolysed tar. Shevardnadze demanded a quick restart for the plant, noting that Georgia could expect oil production to rise shortly. Processing local crude abroad was unacceptable, he said.
CanArgo increased its interest in the Sartichala plant to 51% in November 2000. CanArgo acquired 12.9% interest in the refinery in 1998 by financing a doubling of capacity to 4,000 b/d. The refinery produces fuel oil, diesel, and low-octane gasoline. With acquisition of the further interest, it planned to add a reformer to add high octane gasoline to the product slate.
The Batumi plant runs mainly Russian and Azeri crudes. In 2000 it was running substantially below capacity due to a lack of oil supplies, but the situation was to change with the reconstruction and conversion of the 232-km Khashuri-Batumi oil products pipeline, expected on line in 2001.
The Chevron-financed $70 million project would permit the transport of 100,000 b/d of Kazakh oil to Batumi and free up rail routes that had been used to ship Chevron's Kazakh oil from Tengiz field. Some oil was likely to be supplied by rail to the refinery from other Kazakh sources and from Azerbaijan.
Mitsui & Co. Ltd., Tokyo, was responsible for modernizing the Batumi refinery at a cost of $250 million. Mitsui undertook the work without Georgian government guarantees of its investment. Marubeni Corp. and JGC Corp., both based in Tokyo, dropped out of the project because of a failure to obtain such guarantees. The revamped, more-efficient plant at Batumi was to process 50,000 b/d of crude, double preproject rates.
Mitsui had an interest in the Agip SPA-operated Kyurdashi block in Azerbaijan. If oil were found there in commercial quantities, Mitsui was likely to process some of its share in Batumi.
Georgia might get a new $400 million refinery in Supsa. Plans included an initial capacity of 60,000 b/d, ramping up in phases to 240,000 b/d. Azerbaijan's state oil company, SOCAR, could become an interest-holder.
A refinery at Supsa would receive oil shipments through the existing Baku-Supsa pipeline. The pipeline was expected to transport 120,000 b/d of oil in 2000 from Azerbaijan's AIOC (Azerbaijan International Operating Co.) development, and future volumes transported by this route could increase.
Itochu Corp., which would like to refine its equity-crude production from Azerbaijan in a refinery at Supsa, said it intended to be a participant in this project.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (ARMENIA)

ARMENIA

CAPITAL: YEREVAN
MONETARY UNIT: DRAM
REFINING CAPACITY: NONE
OIL PRODUCTION: NONE
OIL RESERVES: NONE
GAS RESERVES: NONE

Armenia, with a population of 3.5 million, trades mostly with Russia, Turkmenistan, the European Union, and the US.
Energy consumption averages about 5,000 b/d of oil and 49 bcf/year of natural gas, plus an uncertain quantity of electricity.
Some wildcat drilling had occurred, all unsuccessful through 2000. Armenian American Exploration Co. spudded Azat 1 near Garni east of Yerevan on Nov. 27, 1997. It was temporarily abandoned at 3,500 m after encountering minor oil traces.
Drilling cost far exceeded the $10 million minimum expenditure of the 5-year term of the production sharing agreement, hurling AAEC into bankruptcy. The company maintained an office in Yerevan through late 2000 and still hoped to resume operations.
The 106,436 b/d Batumi refinery in Georgia Republic supplied most of Armenia's petroleum products. Armenia in 2000 had no products pipelines, so the shipments moved by truck and rail. Most of Armenia's gas came from Turkmenistan via Russian and Georgian pipelines.
Ethnic and civil disturbances, pipeline accidents, and nonpayment of debts halted gas supplies intermittently. In April 2000 gas shipments, although quickly resumed, were interrupted because of a dispute over payments.
Armrosgazprom, a company owned by the government, Gazprom, and the private Itera Co., handled all gas distribution in Armenia, but the country was looking at the feasibility of diversifying supply.
Iran in particular expected excess gas supply capability to build up from its growing exploration and development activities and suggested construction of pipelines to several countries including Armenia.
Financing had not been obtained by late 2000, but Armenia was seeking funds from the World Bank for such a pipeline and had met with officials regarding Greek participation in the project.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (TAJIKISTAN)

TAJIKISTAN

CAPITAL: DUSHANBE
MONETARY UNIT: TAJIK RUBLE
REFINING CAPACITY: NONE
OIL PRODUCTION: 1,000 B/D
OIL RESERVES: 12 MILLION BBL
GAS RESERVES: 200 BCF

Tajik officials held talks in mid-2000 with Iranian officials about possible Iranian assistance for Tajikistan's oil sector.
The former Soviet republic imported almost all of the 29,000 b/d of petroleum products and 40 bcfd of gas that it consumed, mostly from Uzbekistan.
Tajikistan conducted successful drilling for natural gas in 2000 in the southern Khatlon region, but no details were available, the US Energy Information Administration disclosed. This followed the drilling of two wildcats in 1999.
As of the late 1980s Tajikistan had nine oil, oil and gas, and gas and condensate fields in the Fergana basin bordering Uzbekistan and several identified fields in the Afghan-Tadzhik sub-basin north of Afghanistan.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (KYRGYZSTAN)

KYRGYZSTAN

CAPITAL: BISHKEK
MONETARY UNIT: SOM
REFINING CAPACITY: 10,000 B/CD
OIL PRODUCTION: 1,000 B/D
OIL RESERVES: 40 MILLION BBL
GAS RESERVES: 200 BCF

Kyrgyzstan has significant undeveloped hydroelectric potential and limited oil and gas reserves. Imports provide most of its energy.
State Kyrgyzneftegaz operates some 400 wells in seven fields capable of producing oil or gas and has 2,000 employees.
Undiscovered resources in the republic's part of the Fergana basin are estimated by the US Geological Survey at 840 million bbl of oil and 660 bcf of gas and by the World Bank at 2.8 billion bbl of oil and 10.8 tcf of gas.
Kyrgyz Petroleum Co., owned 50-50 by Kyrgyzneftegaz and Kyrgoil Corp., Calgary, holds the exclusive right to complete, recomplete, and rework producing and nonproducing wells and drill new wells in 12 defined license areas in the Fergana basin in western Kyrgyzstan. The license areas cover a combined 1.6 million acres.
Kyrgoil said incremental oil production from the workover and refracturing of 20 oil wells in Mayli-Su IV field declined from an initial 150 b/d to 39 b/d in 1999. Oil field activity in 1999 was limited to maintenance of the 20 wells previously fractured. This field was discovered in 1948.
Kyrgyzstan was the site of the drilling in 1999 of a single exploratory well, by a local group, outcome uncertain.
The republic imports gas through the Bukhara-Tashkent-Bishkek-Almaty pipeline. The southern part of Kyrgyzstan receives gas from Turkmenistan and Uzbekistan.
KPC's 10,000 b/d refinery at Dzhalal-Abad in the southern part of the republic was built by Petrofac International Ltd. and started up in 1996. It produces A-76 leaded gasoline, A-80 unleaded gasoline, diesel, and fuel oil.
At year-end 1999, Petrofac, renamed Petrofac Resources International Ltd., owned 46% of Kyrgoil, and the refinery was considered collateral for Kyrgoil debt to Petrofac.
The refinery was designed to process typical Kyrgyz 30° sweet crude. Because domestic production is low, KPC imports condensate and naphtha from neighboring countries. Throughput averaged 3,366 b/d in 1999.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (TURKMENISTAN)

TURKMENISTAN

CAPITAL: ASHGABAT
MONETARY UNIT: MANAT
REFINING CAPACITY: 236,970 B/CD
OIL PRODUCTION: 143,000 B/D
OIL RESERVES: 546 MILLION BBL
NATURAL GAS RESERVES: 101 TCF

Growing sales of natural gas to Iran and Russia boosted Turkmenistan's economy to its first recovery since the republic became independent from the former Soviet Union.
At midyear 2000 the country looked toward real GDP growth of 6% for the year. Oil and gas anchor the country's economy.
Establishment of maritime borders in the Caspian Sea were the subject of dispute since the mid-1990s between Turkmenistan and Iran, Kazakhstan, Azerbaijan, and Russia. Of particular interest to Turkmenistan was division of a sizable oil and gas field, called Kyapaz by Azerbaijan and Serdar by Turkmenistan. The disputes delayed development of the 360 million bbl field.
Turkmen officials pointed out that the five countries were going about business in areas indisputably their own and negotiating when disagreements arose in areas where ownership was less clear.
Government action in 1998 resulted in setup of five state oil and gas concerns. They are:
Turkmenrozgaz, responsible for gas exports through Russia.
Turkmenneftgaz, responsible for oil and gas marketing.
Turkmengeologia, responsible for exploration.
Turkmenneft, responsible for oil production.
Turkmenneftgazstroi, responsible for oil and gas-related construction. Upstream developments
Turkmenistan began seeking tenders for exploration and production in the Caspian Sea, and Western Geophysical offered 16,000 line-km of 2D seismic data acquired in 1996-98.
The package included 3,500 line-km of transition zone and land well tie data. Geophysicists with Minneft, Turkmenneft, Turkmengeologia, and Western were interpreting the data.
The package included cross sections showing well log correlation between the Fersman 1, Livanov 12, Livanov 6, Ogurch 1-2, West Ordekli 1, West Ordekli 2, and Chodgaluviev 2 wells.
Canneft Inc., Calgary, signed an agreement in mid-2000 with Turkmengeologia in Ashgabat to evaluate the Adzhiyap oil and natural gas territory, a 2,000 sq km block in southwest Turkmenistan on the border with Iran and along the Caspian Sea coast.
Canneft and Turkmengeologia were to conduct a joint technical evaluation of the Adzhiyap territory during 6 months and were to negotiate for an exploration license.
The technical evaluation would concentrate on the reprocessing of 2,500 km of 2D seismic data, detailed geologic investigation, and infrastructure evaluation.
Canneft said the Adzhiyap territory was a "natural extension" of oil and gas fields contiguous to the block. The company postulated block reserves at 1-3 tcf of gas.
The existing gas pipeline in the Adzhiyap territory and access to the Caspian Sea mitigated the marketing risk, said Canneft.
The Soviet Union was trying to attract foreign investment to Adzhiyap territory even before Turkmenistan became independent.
Another upstream joint venture, Dragon Oil PLC, London, was about to spud the first of three wells at Lam field in the Cheleken Contract Area in the eastern Caspian Sea.
Dragon, almost 70% owned by Emirates National Oil Co. since late 1998, operated a 235,000-acre concession including Lam and Zhdanov fields in 10-30 m of water near the Cheleken Peninsula. The fields produced 8,000 b/d of oil and 1 million cu m/day of gas from 19 wells.
Only 6% of original proved and probable reserves had been produced. Dragon said expansion of production to 80,000 b/d was possible with full field development.
The 25-year contract took effect May 1, 2000. Dragon signed a crude oil swap contract with Naftiran Intertrade Co. Ltd. under which Dragon would ship Turkmen crude to Neka, Iran, and in return receive equivalent barrels at Kharg Island in the Persian Gulf. The swap fee was $17/tonne.
Foreign Minister Boris Shikhmuradov said Turkmenistan wanted to hike oil and gas production to 3 tcf/year and 204 million bbl/year in 2005 from 800 bcf/year and 51 million bbl/year in 1999. Processing activity
Turkmenistan's two refineries are at Chardzou in northeastern Turkmenistan (120,000 b/d) and at Turkmenbashi on the Caspian Sea (116,000 b/d).
Combined throughput was 90,000 b/d in 1999, but the government intended that runs increase to 132,000 b/d in 2000.
A $1.3 billion modernization project was under way at the Turkmenbashi refinery. It included installation of a 1.8 million tonne/year (tpy) catalytic cracker and a 750,000 tpy catalytic reforming unit. The upgrade included a 1.8 million tpy alkylation unit, an 80,000 tpy lubricants unit, and a 90,000 tpy polypropylene unit.
Gent Oil of the UK began work in late 2000 on a $10.6 million desalination facility and a steam furnace, and Emerol Ltd. of Ireland was rebuilding the vacuum unit and adding storage facilities. Transporting Turkmen gas
Turkmenistan reached agreement early in the year to boost gas exports to Iran to 460 bcf/year. The increase was to take effect by yearend 2000. The price was to be $40/cu m.
Shikhmuradov termed the deal a huge increase, claiming that volumes averaged only 70 bcf/year in 1999. A new compressor station to be finished in April 2000 was to boost capacity of the 125-mile pipeline to 460 bcf/year.
Separately, a project to construct a Trans-Caspian Gas Pipeline was developed around a gas sales agreement signed in May 1999 between Turkmenistan and Turkey for delivery of as much as 16 bcf/year of Turkmenistan gas via Azerbaijan and Georgia to Turkey from 2003.
The 1,650 km single-pipe system would originate at the Pustynnaya compressor station in eastern Turkmenistan and involve dual 300 km, 28-in. or larger segments across the Caspian Sea.
The pipeline proponents recognized that gas finds made in Azerbaijan in 1999 changed the supply balance. Alternatives were under study.
Discovery of large gas reserves at Shah Deniz field in the Caspian off Azerbaijan complicated the trans-Caspian route plan.
For Turkmenistan, with its huge and unused gas export potential, the Turkish market represents the sole viable export option, at least in the short term. Iran and Russia were also competing to ship gas to Turkey, and the combined supply offers far exceeded Turkey's projected gas demand for 2001-2010.
Furthermore, Turkmenistan is farther from Turkey than Azerbaijan, and a trans-Caspian line would have to cross Azeri territory.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (UZBEKISTAN)

UZBEKISTAN

CAPITAL: TASHKENT
MONETARY UNIT: SOUM
REFINING CAPACITY: 222,271 B/CD
OIL PRODUCTION: 152,000 B/D
OIL RESERVES: 594 MILLION BBL
GAS RESERVES: 66.2 TCF

Uzbekistan's cumulative foreign investment since becoming an independent state reached $400 million in 1998, far less than that of its neighbors Kazakhstan and Azerbaijan, a US government source said.
Seventeen US companies, including Unocal and Enron, had ceased operations in Uzbekistan through 2000, largely because of the country's less-open and less market-sensitive fiscal policies. The exodus was continuing even though state Uzbekneftegaz said the country's gas reserves ranked among the world's 15 largest.
Uzbekistan's five main oil regions are, from west to east, Ustyurt, Bukharo-Khivin, Southwest Gissar, Surkhan-Dar'ya, and Fergana.
The country has about 160 known fields, 60% of which are in Bukharo-Khivin and 20% in Fergana. Uzbekneftegaz, with budgets of $182 million in 1999 and $166 million in 2000, accounted for most of the drilling.
During 2000 Uzbekneftegaz invited investors to further develop eight of its producing oil and gas fields requiring total outlays of $242 million. North Shurtan, South Kyzylbairak, and Shakarbulak together produced 646,000 tonnes/year of oil. South Tandyrcha, Gumbulak, and Dzharkuduk produced 2.5 bcm/year of gas and 90,000 tonnes/year of condensate.
Uzbekneftegaz said $25 million in investments would be needed at Umid and South Kemachi fields in order to boost output to 100,000 tonnes/year of oil, 30,000 tonnes/year of condensate, and 2 billion cu m/year of gas. It did not mention current production levels.
Also needed were a $45 million gas compressor station at Gaz and a $20 million plant to utilize flared gas at Kokdumalak field.
Company Chairman Ibrat Zainutdinov said Uzbekistan would sell 49% of its shares to foreign investors and sell stock in its other petroleum companies-Uzneftegazdobycha, Uzneftepererabotka, and Uzburneftegaz. Processing activity
The Karaoul Bazar refinery 33 miles east of Bukhara started up in 1997, helping Uzbekistan achieve self-sufficiency in petroleum products.
The $400 million, 50,000 b/d refinery processed condensate produced at Kokdumalak field 55 miles away. Kokdumalak field produced 70% of the country's crude and condensate.
Before independence Uzbekistan's two refineries in Fergana (106,000 b/d) and Alty-Arik (66,000 b/d) relied on crude from a pipeline that originated in Omsk, western Siberia, and delivered oil to Uzbekistan by way of Chardzou, Turkmenistan. By 1995, these crude imports were largely eliminated.
The Bukhara refinery has units for atmospheric distillation, naphtha hydrodesulfurization, gas oil hydrodesulfurization, kerosine sweetening, regenerative reforming, sour-water treatment, and sulfur recovery. It also has a gas plant, one control station, and two electricity substations.
In 2000 it produced gasoline for export as well as gasoline, diesel, and kerosine for the domestic market. The Uzbekistan government planned to double the refinery's capacity.
In 1997, Mitsui and Toyo Engineering Corp. undertook a $200 million desulfurization capacity expansion project at the Fergana refinery to permit the production of low-sulfur diesel. Texaco was involved in a joint venture to produce and market Texaco-branded lubricants from the Fergana refinery.
The Alty Arik refinery needed to be mothballed or rebuilt.
Most of the country's gas, which is high in sulfur, is routed through the 2.7 bcfd Mubarek gas processing and treatment plant. ABB Lummus was to have completed construction of the $1 billion Shurtan petrochemical plant by year-end 2000. ..

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (KAZAKHSTAN)

KAZAKHSTAN

CAPITAL: ASTANA
MONETARY UNIT: TENGE
REFINING CAPACITY: 427,093 B/CD
OIL PRODUCTION: 627,000 B/D
OIL RESERVES: 5.417 BILLION BBL
GAS RESERVES: 65 TCF

Kazakhstan is a former Soviet republic with an area almost four times the size of Texas.
Coal provided more than half of the republic's primary energy in 1991-98, but Kazakh coal production declined by roughly a third in 1999 because of declining exports and other reasons.
Oil production in 2000 was rising. The government said overall production potential exceeded 3 million b/d. Achieving this level was expected to take more than a decade—if it ever could be reached at all.
Gas shipments were more constrained by lack of pipeline capacity than was oil transport, and about 40% of the country's gas reserves were in one field, Karachaganak.
Kazakhstan had to either negotiate to connect its fields to existing Russian pipelines or build its own pipelines. Large volumes were being flared.
The country had six gas pipelines divided into two networks in the west and southeast. The government had considered building a pipeline from the western producing fields to population centers in southeast Kazakhstan. Upstream developments
Kazakhstan's government expected crude and condensate production to increase for several years. More than half of the crude and condensate the country produced in 2000 was exported.
At end-2000 production was failing to meet its 2000 forecast of 660,000 b/d but nevertheless was rising. Its forecasts were for 750,000 b/d in 2001 and 830,000 b/d in 2002.
Most of the growth was to come from Tengiz and Karachaganak fields and start-ups such as North Buzachi, Sazankurak, Saztobe, Airankol, and others. Also, Alibekmola, Urikhtau, and Kozhasay fields were to be producing by 2002.
With all Kazakh production coming from onshore fields, the nine-company Offshore Kazakhstan International Oil Co. made the country's first discovery in the Caspian Sea. Kashagan East 1, 47 miles southeast of Atyrau, was the first find on the Kazakhstan shelf.
OKIOC spudded a well on the Kashagan West 25 miles distant. Kashagan East 1 cut an oil-bearing interval in Paleozoic carbonates below 13,000 ft. The group was to test two zones but announced only results from the lower zone. It flowed as much as 3,700 b/d of 42-44° gravity oil and 7 MMcfd of gas. Results of the second zone to be tested were not announced by late in the year.
The world's only arctic-class barge rig, Sunkar Rig 257, owned by Parker Drilling Co., Tulsa, Okla., drilled the well in 10 ft of water. The PSA covers almost 1.4 million acres.
Supergiant Tengiz field east of the Caspian was averaging 275,000 b/d of oil, and supergiant Karachaganak gas-condensate field was averaging 50,000 b/d of condensate in fall 2000. Together the fields produced about half of Kazakhstan's crude and condensate.
Karachaganak, near the Russian border west of Orenburg and operated by a BG PLC group, was also making 250 MMcfd of gas. The group let contracts to Baker Hughes Inc., Saipem SPA, and Parker Drilling Co. to manage and conduct development, drilling, and workover operations there.
First International Oil Corp., Houston, was the largest interest holder in the Precaspian basin with 9 million acres. FIOC began exporting crude from its first field, Sazankurak, in April 1999. Its exports from this area of the Precaspian basin reached 4,000 b/d in mid-2000 and were to rise to 6,000 b/d by yearend 2000 with further development drilling.
With nearly full interests in five blocks, the company had a close strategic alliance with Geotex JSC, Kazakhstan's main geophysical services company.
A joint venture led by Hurricane Hydrocarbons Ltd., Calgary, averaged 90,000 b/d in fall 2000 from the Kumkol fields in the South Turgay basin. It expected to have averaged more than 80,000 b/d for all of 2000. The company drilled a dry wildcat at Kumkol East, and the board authorized management to proceed with development of Qyzylkiya, Aryskum, and Maibulak (QAM) fields. The fields had 22 wells capable of production but were not producing.
Hurricane also participated with RWE-DEA AG, Gaz de France, and International Finance Corp. in Akshabulak oil field, which it said averaged 6,000 b/d in 1999. The group, known as Kazgermunai, also had rights to Nurali and Aksai fields.
Kazakh state natural gas pipeline operator KazTransGas has won a tender to develop the Amangeldy gas fields in Zhambyl oblast. The $120 million project was to tap 25 bcm of reserves and reduce southern Kazakhstan's dependence on gas from Uzbekistan. Demand was about 1.5 bcm/year.
Late in the year American International Petroleum Corp., New York, reentered and was to evaluate oil potential in an untested Jurassic zone in the Begesh 1 well on a 12,000 acre structure on 4.7 million acre License 953 in southwestern Kazakhstan. The Upper Jurassic was untested in this well and known to be productive in nearby Karakuduk oil field.
Trio Gold Corp., Calgary, was attempting to rejuvenate and explore Blinovskoe oil field on a 59,697 sq km property in the Kyzyl-Orda region. Processing activity
Kazakhstan has three refineries with combined capacity of 427,000 b/d. While this is far below the country's oil production, domestic consumption fell to 130,000 b/d in 1999 from 430,000 b/d in 1990.
Plans were announced for two new refineries in Kazakhstan: a $1.5 billion, 150,000 b/d plant in Mangistau and a $480 million, 50,000 b/d export refinery at Zhanazhol field near Atyubinsk. Based on 2000 utilization and expected growth, however, investment support was considered questionable.
The Pavlodar refinery in northeast Kazakhstan and the Shymkent or SHNOS refinery in south-central Kazakhstan can process 163,000 b/d and 160,000 b/d, respectively. They were built to process crudes from western Siberia, delivered via the Omsk-Pavlodar-Shymkent-Chardzou pipeline.
Atyrau in western Kazakhstan has the country's oldest refinery. Close to the Caspian Sea, with capacity of 104,000 b/d, it was the country's only refinery designed to use local crudes.
Russia supplied only 14,400 b/d of oil to Kazakhstan in 1999-2000. As a result Pavlodar, the most complex of the three plants with catalytic cracking, thermal, and coking capability, ran at 9% of design capacity.
Pavlodar was crippled by competition from Russia's Omsk refinery (part of Russian integrated company Sibneft) 350 km to the north. Deliveries of crude to Pavlodar plummeted after the Omsk refinery expanded its capacity to 600,000 b/d.
SHNOS was designed to process western Siberian oil as 80% of its feedstock. In 2000 it relied largely on oil from Kumkol and other Kazakh fields in the South Turgay basin operated by Hurricane and Russia's Lukoil. It also had access to rail crude deliveries from Uzbekistan and from the China National Petroleum Co.'s Aktyubinsk fields in the west.
SHNOS processed 68,000 b/d of oil (42% of design capacity) in 1999. In 2000 it was adding a catalytic cracking complex, which would increase its output of light oil products from 65% to 85% of its output slate.
SHNOS supplied about 65% of the refined products used in the country's southern regions. In 1999, the refinery produced diesel, gasoline, kerosine, and fuel oil. Close to 50% of output was consumed in Almaty.
The Atyrau refinery was in a paradox. Oil extraction in the western part of Kazakhstan was rising, but refinery output was declining. Atyrau processed 54,000 b/d of crude, or 52% of capacity in 1998 and only 38,000 b/d in 1999.
Built in 1945, Atyrau is the simplest of the country's three refineries. It takes crude from Mangyshlak, Tengiz, and Martyshin fields.
The refinery needed $450 million in investments to obtain a catalytic cracker, which would allow it to process 90,000 b/d. Japanese banks were prepared to finance the upgrade, which Marubeni would undertake. The refinery revamp would boost the production of light products to 80% of capacity.
Atyrau produced 76 and 93 octane gasolines, diesel, heating oil, aviation kerosine, and fuel oil. Transportation
The government set up an interdepartmental commission for matters of export oil and gas pipelines to be headed by Prime Minister Kasymzhomart Tokayev.
The Caspian Pipeline Consortium performed final welding in late November 2000 of its 1,580-km oil pipeline from Tengiz field to Novorrossiysk on the Black Sea. Ahead-of-schedule completion kept the $2.5 billion project on track for start-up in mid-2001. Export capacity was to be 600,000 b/d initially and 1.5 million b/d ultimately.
Chevron called the line "a major step forward in the development of Russia's and Kazakhstan's oil reserves." It would carry crude from Tengiz and other Russian and Kazakhstan fields.
The Kazakhstan government tapped TotalFinaElf SA to study feasibility of a Kazakh-Turkmen-Iran oil pipeline that would run from Kashagan oil field in the Caspian through Turkmenistan to Neka, Iran. The line would carry 500,000 b/d initially and 1 million b/d eventually to refineries in northern Iran.
The Ministry for Energy, Industry, and Trade let a $600,000 contract to Gustavson Associates Inc., Boulder, Colo., to find ways to utilize the country's plentiful natural gas resources.
The ministry noted that its "Soviet-vintage" pipeline network was ill-equipped to fuel anticipated growth in Kazakhstan.
It said Gustavson would investigate gas production forecasts from Kazakhstan's known fields and the potential for discoveries. It also would look at domestic demand for gas from the country's electricity, chemical, and other primary industries. The study would also focus on
Kazakhstan's industrial sectors, particularly chromium and aluminum.

Source: http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

Energy Research Group (AZERBAIJAN)

AZERBAIJAN

CAPITAL: BAKU

MONETARY UNIT: MANAT

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

Energy Research Group (RUSSIA)

RUSSIA

CAPITAL: MOSCOW

MONETARY UNIT: RUBLE

REFINING CAPACITY: 5,435,480 B/CD

OIL PRODUCTION: 6.35 MILLION B/D

OIL RESERVES: 48.6 BILLION BBL

GAS RESERVES: 1,700 TCF

Russia's economy bounced back in 2000 after rough going only 2 years earlier. Russia's economy appeared to be in its best shape since the Soviet Union's collapse in the early 1990s.
With high oil and gas prices, oil production, formerly in steady decline, had almost stabilized. The country continued a wave of privatization efforts. In November 2000 the government ordered Gazprom to allow other companies to use as much as 15% of its pipeline capacity.
Russia was exporting 4 million b/d of oil and stood to benefit from an October 2000 pact in which the European Union agreed to help Russia develop its oil and gas reserves in return for a long-term supply commitment.
Radical changes to the Russian tax code, put into place by President Vladimir Putin at midyear 2000, were to affect expatriate workers within the Russian Federation.
The principle changes included a much lower, flat rate of tax for residents and a higher tax rate with a broadened liability for nonresidents. Nonresidents would be taxed on income attributable to Russian activities, regardless of whether payment is made from a source (i.e., a bank account) in Russia. Upstream developments
Russia in 2000 was trying to use joint ventures and production sharing contracts to diversify its oil and gas production.
About 90 fields produced 75% of Russia's oil, and 80% of its gas production originated from three fields, Urengoi, Yamburg, and Orenburg.
Russian officials told the 2000 World Petroleum Congress the country wanted to mount, with outside participation, a massive offshore exploration program. They said the extensive continental shelf areas had only 1 million line-km of 2D seismic data and 170 wells. That included 47 wells in the Barents Sea and 64 wells in the Sea of Okhotsk. A regional look at Russian offshore activity follows.
Russian Caspian Sea. Lukoil said a well in the northern Caspian sea discovered Khvalynskoye field on the Severny license. It said the field, the first found on Russia's Caspian shelf, could contain 2 million bbl of oil. It was building a jack up capable of drilling to 8,000 m in 800 m of water to appraise and develop the field.
Later in the year Lukoil, Yukos, and Gazprom signed charter documents in Moscow setting up Caspian Oil Co., a joint venture to explore for and develop oil and gas reserves in the Caspian region. Establishment of the JV was to allow joint investment from the founders to develop reserves.
The company was to seek licenses for exploration on promising structures in the shallow waters of the North Caspian.

Russian Far East. Sakhalin Energy Investment Co. Ltd., then led by Marathon Oil Co., became the first company to develop a Russian offshore field when it started oil production from the Astokh portion of Piltun-Astokhskoye field in the Sea of Okhotsk off Sakhalin Island in July 1999. Exports began in September 1999.
Marathon traded its 37.5% stake to a Shell affiliate in late 2000.
First efforts as part of the project took place nearly a decade earlier. The field is 10 miles off the island in 100 ft of water.
Part of the Sakhalin II project, Piltun-Astokhskoye oil and gas field and Lunskoye gas field had combined reserves of 1 billion bbl of oil and condensate and 14 tcf of gas.
Initially the field was to be produced only during the ice-free part of the year. Production was to reach 90,000 b/d by the start of the second producing season in 2000. Associated gas was to be reinjected into the reservoir until transport facilities were built.
Marathon said production could peak at 200,000 b/d of liquids and 2 bcfd of gas when both fields were fully developed.
During 2000 Exxon Mobil found a "significant" oil accumulation with a step-out to Chayvo gas field on one of its Sakhalin I blocks. The Chayvo-6 appraisal well penetrated an oil-bearing Miocene reservoir that flowed at a test rate of 6,000 b/d of oil. The well cut a 340-ft oil column on the west flank of the Chayvo structure. Chayvo-6 was drilled in 50 m of water to TD 10,089 ft.
An Exxon Mobil group was studying the eventual shipment of gas from Sakhalin Island to Japan via pipeline.
The company said the project could transport gas from Sakhalin I and other potential projects off northern Sakhalin Island to Japan. It said that it had identified a gas resource of 10 tcf on the Chayvo block, which had potential for further oil and deep gas reserves, and that other resource additions were possible on the Arkutun-Dagi and Odoptu blocks.
Gas from Sakhalin I and II fields could also fuel a proposed electricity-generating station. Unified Energy System, Russia's electric utility, at midyear proposed a $9.6 billion project to supply electricity to Japan.
A 4,000 Mw steam-gas electric station to be built on Sakhalin would supply 25.5 billion kw-hr/year of electricity to Japan by 2012. One fourth of that amount would be delivered to the grid on the northern Japanese island of Hokkaido and the rest to the Honshu grid, UES said.
The project also involved construction of 1,400 km of transmission lines. The electricity was to cost 2¢/kw-hr to generate and 3¢/kw-hr to transmit and would sell for 6-8¢/kw-hr in Japan.
Representatives from Magadan Province of far eastern Russia were assessing interest late in 2000 in a lease sale 50 miles offshore in the Sea of Okhotsk in mid to late 2001.
Western Siberia. Four large western Siberian fields contributed more than half of Russia's oil production in 2000.
Most joint ventures with western oil companies were in western Siberia, in the Tyumen region, but overall output in the area was in decline.
Russia's most productive oil fields in western Siberia were Samotlor, Mamontov, Fedorov, Lyantor, Krasnolenin, Vatyegan, and Sutormin.

Putin in September 2000 welcomed the signing of agreements governing parts of a $672 million loan package for Russia's Tyumen Oil Co. Tyumen Oil was to use US equipment and services and US and Russian labor.
Halliburton Co. was to use $292 million of the 10-year loans to fund a 3-year project to stop the decline and maintain production of Tyumen's 320,000 b/d of crude interest in Siberia's giant Samotlor oil field. Halliburton would also use $93 million in other unsecured loans for the project.
Enterprise Oil PLC, London, boosted to 18.6% its holding in Khanty Mansiysk Oil Corp., registered in Delaware.
KMOC held production licenses on 10 fields near Khanty Mansiysk in the Tyumen region of western Siberia. Production exceeded 11,000 b/d in third quarter 2000, up from 6,500 b/d in 1999. Not all of the fields were on stream. A western engineering report attributed 420 million bbl of reserves to the fields.
The fields are East Kamennoye, Potanay-Kartopinskoye, Chernogorskoye, Paitykhskoye, Sredne-Nazymskoye, Galyanovskoye, Bolshoye, Olkhovskoye, Aprelskoye, and Tsentralnoye.
CanBaikal Resources Inc., Calgary, started production through a new 28-km pipeline in August 2000. The initial 450 b/d rate, from a well in Kulun pool, was to rise quickly to 650 b/d. Production from a second well, at Untegey North, was to start shortly after freeze-up, when the well was fractured.
Gazprom and another Shell affiliate were in early stages of a project to develop Zapolyarnoye field in Yamal-Nenets Autonomous Okrug 200 km northeast of Urengoi gas field. Shell said Zapolyarnoye's Neocomian aged reservoirs held 750 million tonnes equivalent of gas, oil, and condensate.
Volga-Urals. This region produces less than 25% of Russia's oil. Russia's most productive oil fields in the Volga-Urals in 2000 were Romashkino and Arlan fields, both in advanced stages of depletion.
Barents-Kara-Timan Pechora. Gazprom was to sign a production-sharing agreement involving development of oil reserves at Prirazlomnoye gas field on Russia's Barents Sea shelf. Rosshelf Co., project operator, in the fall received the first payment on a large loan from Germany's Wintershall AG to begin development.
Gazprom signed a $1 billion memorandum of understanding with Wintershall AG, a unit of BASF, to collaborate in developing the oil reserves. Gazprom, primarily a gas concern, was expanding its oil business. This pact would allow it to diversify its operations and lessen its dependence on gas.
Prirazlomnoye held an estimated 80 million tonnes of oil. Wintershall and Gazprom planned to create a 50-50 joint venture to develop the field, expected to produce first oil by 2003.
Russia also looked forward to development of supergiant Shtokmanovskoye gas field in the Barents Sea about 350 miles northwest of Prirazlomnoye.
Shtokmanovskoye lies 1,200 km east of the Snøhvit complex in the Barents off northern Norway.

Russian geologists had said that 2 million sq km of Russia's arctic shelf were favorable for oil and gas. Assessed resources of the shelf were placed at not less than 700 billion bbl of oil equivalent.
Shtokmanovskoye, discovered in 1988, had difficult economics despite its size. Development would involve a $10-20 billion, three-platform project with first gas in 2008.
With reserves of 3.2 trillion cu m, the field is in 300 m of water and has a reservoir of Jurassic age some 4 km subsea.
Eastern Siberia. Federal lawmakers included BP Amoco PLC's biggest Russian gas project, Kovyktinskoye field in the Irkutsk region, on the list of sites covered by production sharing agreements, which offered tax breaks to investors. The Duma approved the law.
BP held about one fourth of Russia Petroleum, which owned the rights to develop most of Kovyktinskoye. The field, one of the world's largest with an estimated 1.4 tcm of reserves, was in for a production hike to serve China.
The company planned to build a pipeline to ship 20 bcm/year of gas to China and 10 bcm/year to South Korea during 30 years. Processing activity
Russia's refineries needed to be modernized.
Many of them were built piecemeal over decades and in 2000 had relatively new units alongside aging equipment. The greatest need was for conversion equipment to enable plants to make light products.
The other part of the loan involving Samotlor field to Tyumen Oil Co., totaling $217 million in loan guarantees, was for upgrading of the Ryazan refinery 120 miles southeast of Moscow. A further $70 million in financing for the Ryazan project was to come from other unsecured sources. Transportation
Russia was slowly moving to upgrade pipeline transport and export capabilities.
The Baltic Pipeline System involved construction of ports at Ust-Luga, Bukhta Batereinayaat, and Primorsk on the Russian Baltic coast. Primorsk was to take 10 years to build, but the other two ports were to be ready at end-2001. Russia was to ship western Siberian oil to the ports for trans-shipment to Baltic countries.
Russia and China signed a memorandum in mid-2000 under which construction would begin in 2003 on a 2.2 million b/d pipeline to ship western Siberian oil to eastern China.
The Blue Stream pipeline under construction at yearend 2000 across the Black Sea to Turkey was the centerpiece of Russian efforts to boost gas exports.
Gazprom and Kazakhstan's Kaztransgaz agreed to form a state-owned Russian-Kazakh natural gas joint venture. Gazprom was to replace Tractebel of Belgium as exporter of Kazakhstan's gas.
Kazakhstan was counting on the Russian gas giant for help in implementing a number of important projects, including delivery of gas to Europe and joint sales on the Chinese market. It also desired to enter into swaps under which Russia delivered gas to the Kustanai region in northern Kazakhstan and the Aktyubinsk region in western Kazakhstan in exchange for gas from Kazakhstan's Karachaganak field.

Source:http://www.pennwellpetroleumgroup.com/articles/ipe_print_toc.cfm?volume_num=2001

China Promotes Biofuels as Energy Alternatives

China promotes biofuels as energy alternatives
By OGJ editorsHOUSTON, Jan. 19 -- Promoting biofuels as an alternative to petroleum products, the Chinese government has set a goal of producing 2 million tonnes/year of biofuels by 2010 and 10 million tonnes/year by 2020, reported analyst Lijuan Wang of FACTS Inc., Honolulu.
China has become the third largest producer of bioethanol, following Brazil and the US. By the end of August 2006, it had approved four bioethanol fuel companies, which have completed facilities having a total production capacity of 38,100 b/d, Wang said.
Sinopec and PetroChina produce and distribute bioethanol fuel products through their retail networks. Bioethanol gasoline, sold in 27 regions in nine of China's provinces, accounts for 20% of China's total gasoline consumption, meeting the goals of the government's 10th 5-year plan. China will continue to promote bioethanol fuel use in its plan for 2006-10, Wang added.
The country's biodiesel industry, however, is still in its infancy. China has not yet established unified standards for biodiesel production or officially approved any biodiesel projects, although it is taking steps in both directions. It has encouraged Sinopec and PetroChina to produce biodiesel and introduce it into their retail networks, and Sinopec has set up a biodiesel production standard that is awaiting governmental approval.
Six private and local companies produce the country's 4,300 b/d of biodiesel, but many small local biodiesel projects are being planned or are under construction.
ChallengesChina's main challenges in developing both bioethanol gasoline and biodiesel are tightening feedstock supply and price increases, "which will constrain the increase in the number of ethanol fuel producers in China," Wang reported.
To encourage bioethanol production, the government created tax incentives, and both national and local governments have provided subsidies promoting the use of old grain. However, these subsidies are being reduced as China encourages a wider range of nongrain feedstock. In mid-2006 the government said future supported biodiesel would be produced from oil-bearing seeds and plants to augment use of waste oil from restaurants. In addition, future supported bioethanol fuel would be produced by biomass materials, such as sugarcane, cassava, and corn and wheat stalks.
Although both bioethanol fuel and biodiesel in China can continue to expect benefits from preferred governmental policies and loan approvals, such incentives may not guarantee success in meeting the official goals, Wang said. Feedstock crops require too much land and are at odds with agriculture, and "some projects may fail due to the competition of capital, technologies, and product quality."
Source: http://www.ogj.com/articles/article_display.cfm?article_id=282599