OGJ Newsletter

• U.S. Industry Scoreboard 3/11 [72514 bytes]

Major new investment will be needed by 2000 in Latin America's refining/marketing sector to meet surging refined products demand in the region.

So says East-West Center's Fereidun Fesharaki, who predicted at the InterAmerican Petroleum and Gas Conference (IPGC) last month in Dallas industry would have to spend as much as $20 billion on Latin American refining and $20 billion on refined products transportation, storage, and distribution the next 4-5 years to meet expected demand. The growth in refined products demand will place a big squeeze on Latin American refineries, he contends, with the likelihood that the region will be a net importer of products in 5-10 years.

Even if Latin America remains a net oil importer, the region's exports of refined products are likely to grow to 3 million b/d by 2020 from 1.5 million b/d in 1992. That's the view Petrostrategies' Allen Mesch gave at IPGC, predicting Latin American/Caribbean (LAC) refining capacity will rise to as much as 9.1 million b/d by 2020 from 6 million b/d in 1992. Dominating that growth will be added distillation, reforming, and deep conversion capacity-the latter because of a growing surplus of fuel oil. The biggest growth will come in gasoline at 2.6%/year, says Mesch. Growth of products exports in the region will be concentrated in the Caribbean, he contends, with refineries there meeting almost all of the incremental growth in U.S. demand for imports of LAC products.

Meanwhile, other factors point to the attractiveness of Latin America as a place for industry to invest. Despite projected GDP growth of 3.5%/year, Latin America's standard of living is likely to erode further the next 5 years, bolstering interest in foreign investment there. So predicts ARCO Chief Economist Anthony Finizza, who notes economic freedom-a measure of fiscal reforms, open trade policies, and other factors-is improving in Latin America.

Eight operators and Britain's Department of Trade & Industry have funded research by AEA Technology, Didcot, U.K., designed to improve gas/condensate reservoir management. AEA aims to complete by August 1998 development of reservoir simulation software that will help operators better determine how many wells are needed for gas/condensate field development. The system will provide models to predict relative permeabilities of gas and condensate in reservoirs to give a picture of liquid flow rates. AEA notes that as reservoir pressure falls with gas production, dewpoint falls, forming liquids that can impede the flow of gas to wells. Understanding how this occurs is crucial to determining how many wells will be needed. The system is intended as a predictive tool, notably for high temperature/high pressure discoveries and deep structures.

Norway's Department of Industry and Energy was expected at OGJ presstime to announce details of Barents Sea acreage to be offered in a new license round. So far several large gas discoveries have been made in the central part of the sea, but no commercial oil has been found.

Statoil's 7128/4-1 wildcat made the first producible oil find in the region, but the well flowed only 157 b/d of oil on test, and Statoil decided against further testing (OGJ, Feb. 28, 1994, p. 30). Since then Statoil, Norsk Hydro, and Saga have pooled Barents data to see if more exploration is worthwhile. The three firms were later joined by foreign operators, and a working party then recommended to the ministry which Barents blocks should be offered for exploration.

Meanwhile, Norway's operators expect good results from drilling on blocks awarded in Norway's 15th offshore licensing round (OGJ, Jan. 29, p. 36).

This opened prospective acreage mainly in the Norwegian Sea plus some blocks in the Norwegian North Sea. Phillips may be the first to drill on 15th round acreage. It has chartered Transocean 8 semisubmersible rig to drill one well east of Troll field with an option to drill a second in the fourth quarter.

As talks are expected to get under way early this week in New York between Iraqi and U.N. officials over limited oil sales to fund humanitarian supplies, rumors continue to fly. A Baghdad newspaper owned by Saddam Hussein's son has suggested Iraq will accept the U.N. resolution. But Iraqi officials say there are points that need further discussion.

Middle East Economic Survey (MEES) says Abd Al-Amir Al-Anbari will again lead the Iraqi delegation, but his mandate is restricted to technical matters.

"There are persistent reports," said MEES, "that Deputy Prime Minister Tariq Aziz will join the Iraqi delegation soon afterwards. If Mr. Aziz enters the scene, he will presumably handle the political and diplomatic aspects of the talks."

Russia and Iran continue to press for cooperative, multinational development of Caspian Sea oil and gas. But Azerbaijan isn't waiting on a regional solution, as seen with the Azeri parliament's Mar. 1 ratification of a November 1995 production sharing agreement (PSA) between state owned Socar and an international group covering appraisal and development of the Karabakh structure.

Karabakh, with reserves estimated at 1 billion bbl of oil, is in 600 ft of water in the Azeri Caspian 12 miles north of the Azeri-Chirag-Guneshli tract where Azerbaijan International Operating Co. has proposed a $7.95 billion development (see related story, p. 104). Karabakh partners are Agip, Russia's Lukoil, Pennzoil, and Socar. Karabakh PSA, which includes a 3 year drilling and seismic commitment and 25 year production period, plus exploration and production options, took effect Feb. 23.

U.S. Sen. Alfonse D'Amato (R-N.Y.) continues his bluster aimed at non-U.S. companies studying oil and gas projects with Iran-and it may be working.

D'Amato, leading the push to expand U.S. sanctions against Iran, last month warned Australia's BHP, seeking to lay a pipeline from Iran to Pakistan, and Japan's JGC Corp., negotiating a service contract to develop three onshore gas fields in Iran, against rushing into any deals ahead of legislation giving President Clinton discretionary power to punish non-U.S. firms for doing business in Iran's oil and gas sector. D'Amato had threatened to grandfather existing projects into the legislation. BHP says it will abide by any U.S. law tightening sanctions on Iran "as applicable," and JGC says it is unlikely to sign a contract with Tehran because of a lack of financing and the current economic and political situation in Iran. BHP also says it strongly opposes efforts to apply legislation extraterritorially.

The three gas field projects are part of a larger tender by National Iranian Oil Co. (NIOC) to foreign companies last year involving 10 hydrocarbon projects.

International newswires report other Japanese firms contacted in Tehran are reluctant to pursue any of the 10 projects because of concerns over U.S. legislation and the economic viability of projects.

North American petroleum companies are getting more fiscal relief from government.

Canada's oilsands industry is getting another boost, as Ottawa has extended federal mining tax regulation to include in situ operations and expanded accelerated capital cost allowance to cover a broader range of investment.

Industry leader Syncrude praised the rule changes, noting oilsands had been Canada's only industrial sector still without generic fiscal terms. The new tax rules, coupled with royalty relief disclosed last fall, reflect recommendations of a national task force that estimates oilsands development in Canada could involve as much as $21-25 billion (Canadian) in investment the next 25 years.

U.S. Bureau of Land Management, which recently cut federal royalties for heavy oil production (OGJ, Feb. 19, p. 28), now is looking at relief for marginal gas wells.

BLM invited public comment on the issue, seeking how to determine if royalty relief is necessary, define a "marginal" gas property, and minimize the administrative burden on government and producers in a royalty relief program.

FERC has decided to take water depth into consideration when it determines whether an offshore pipeline is primarily a natural gas gatherer or a transporter.

FERC will establish a presumption that the system is a gatherer if it operates in 200 m or more of water, thus exempting it from jurisdiction. It contends this will encourage deepwater E&D. Within the 200 m boundary, FERC will continue to apply its existing yardstick, the primary function test, at the point where the project is close to established transmission facilities.

FERC applied the new policy when it approved a construction certificate for Shell Gas Pipeline Co.'s proposed West Delta 143 pipeline in the Gulf of Mexico.

DOE is accepting offers until Apr. 30 from companies interested in buying or leasing Strategic Petroleum Reserve facilities in South Louisiana.

DOE wants to sell a 67 mile, 36 in. pipeline connecting the Weeks Island SPR storage site near New Iberia to the St. James marine terminal on the Mississippi River. DOE no longer needs the line because it is closing the Weeks Island site (OGJ, Mar. 4, p. 46). DOE also wants to sell or offer for lease the St. James terminal-with six storage tanks, two docks, and connections to Capline and Locap pipelines. In addition, DOE wants to offer for lease a 36 mile, 36 in. pipeline from the Bayou Choctaw SPR site to the St. James terminal. It would retain rights to use the facilities to draw down SPR crude in an energy crisis.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.