OGJ Newsletter

Declines in OECD storage indicate that overproduction by the 10 active members of the Organization of Petroleum Exporting Countries above their assigned quotas is not dumping a surplus of oil on markets as some fear, Rothman said.

OECD storage in Europe fell an estimated 8 million bbl during October, compared with a normal build of 1 million bbl. That draw was led "by declines in gasoline and middle distillates, i.e., heating oil (and) diesel," Rothman said.

"Using data for the US as a guide, OECD North America inventories are estimated to have fallen 12 million bbl, 2 million more than normal," he said. "We estimate that two-thirds of the total storage decline occurred in stocks of 'other oils'—a petroleum storage category reported only by the US Department of Energy."

As for OECD members in the Pacific region—Japan, South Korea, Australia, and New Zealand—"guidance suggests that stocks rose 6 million bbl during the month vis-à-vis the normal build of 5 million," Rothman said.

Energy prices react to warning

Energy futures prices jumped Nov. 21 after US President George W. Bush and Russian President Vladimir Putin jointly warned Iraq to cooperate with United Nations' weapons inspectors. That capped a 3-day rally in oil futures markets; prices took a steep dive Nov. 25 but rebounded some in the next session in short covering by traders ahead of the Thanksgiving holiday. Reported declines in US stocks of oil and distillates through Nov. 22 also helped buoy prices.

Recent rises in oil futures prices "may one day prove to represent the tip of a new iceberg regarding angst about Iraq and general supply security measures," Rothman said.

Arrival of United Nations weapons inspectors in Iraq and the looming Dec. 8 deadline for that country to report all weapons of mass destruction that it is holding "have all the makings of generating concern about a potential confrontation between Baghdad and US-led forces, particularly given the overt background indications about the US readying itself for war," he said in a Nov. 18 report.

That is a far cry, he said, from previous assumptions among "most traders and analysts" that "Saddam was off the hook" after agreeing to the arms inspections "and that oil supplies from Iraq were poised to expand on a sustained basis."

Meanwhile, initial estimates for November indicate that oil production from the 10 active OPEC members has fallen to 24.3 million b/d from 24.6 million b/d in October. The primary reductions were by Saudi Arabia and Iran, said Matthew Warburton, an analyst with UBS Warburg LLC in New York.

"The trend supports our view that OPEC-10 supply has peaked as producers have built as much prewar external inventory close to consuming markets that they need," he said.

Tyler Dann, an industry analyst in the Houston office of Banc of America Securities LLC, said industry sources indicate "some spare capacity was used last month" to boost "wartime" oil supplies, "particularly in and around Saudi Arabia," as a precautionary measure, "perhaps both on land and at sea inside tankers."

Algerian Energy and Mines Minister Chakib Khelil said last week that OPEC members would take measures at their Dec. 12 meeting in Vienna to support oil prices in a range of $22-28/bbl. He acknowledged that overproduction is happening but is not creating problems yet. However, if the winter in the Northern Hemisphere proves to be mild, that could require another cut in OPEC output, Khelil said.

However, Dann said, "While it is bullish to think that OPEC is beginning to address the issue of overproduction ahead of next year, it is bearish in the sense that OPEC tends to react based on (its) view of immediate demand in the market. Thus, it doesn't appear as though OPEC sees much demand in the market at present."

Little fuel switching evident

Although natural gas prices have risen above residual fuel oil prices along the East Coast, no more than 500 MMcfd of gas demand has been lost to fuel switching so far this year, said Robert Morris with Salomon Smith Barney Inc., New York, in a Nov. 21 report.

"Based solely on price comparisons, city gate natural gas prices lost their advantage to city gate residual fuel oil prices about 4 weeks ago in the Northeast and roughly 6 weeks ago in the Southeast, although natural gas prices have not yet risen above residual fuel oil prices (along) the Gulf Coast," he said.

"However, the economic incentive to switch also depends on incremental residual fuel oil transportation costs, taxes, and associated emission credits. At the same time, contractual obligations and the time required to purchase and transport residual fuel further limits certain users' ability to switch near term without assurance that a price disparity will persist," he said.

Therefore, Morris forecast that the amount of US gas demand at risk of getting lost to fuel switching is around 4 bcfd, or 7% of annual demand, if natural gas prices remain higher than residual and distillate prices "for an extended period."

Industry Scoreboard

null

Due to Holiday in the US, data for this Week's Industry Scoreboard is not available.

null

Industry Trends

THE Worldwide oil field process chemicals market is expected to grow to $2.3 billion by 2007 compared with $1.7 billion in 2002, forecast Norwalk, Conn.-based Business Communications Co. Inc. (BCC) in a new report.

That pace would mean an average annual growth rate (AAGR) of 6.6%. Currently, drilling and production chemicals account for 76% of the total market.

Enhanced oil recovery chemicals are forecast to grow the fastest of the field chemicals (see table).

Production chemicals are expected to continue to dominate the oil field chemicals market in 2004, while drilling chemicals are expected to maintain the second largest market share with 36% of the total.

Stimulation, completion, and workover fluids will remain relatively stable, BCC said.

The field process chemicals market is expected to peak during 2005-10, BCC said. Many experts predict that oil production will peak in the same time frame based upon known oil reserve data, BCC said.

"If these estimations materialize, a decline in oil drilling, exploration, and production would begin after 2005 and continue until the cost to produce oil becomes prohibitive.

"Demand should increase for natural gas, which is considered to be in abundance," BCC said

OIL AND NATURAL GAS information technology (IT) specialists continue to develop electronic-business models despite the e-commerce meltdown in 2000.

The industry must move beyond unrealistic business models and concentrate on what works, said Bill Swanton, vice-president and research fellow with the Boston consulting firm of AMR Research Inc. He spoke at a Nov. 11 meeting of the Petroleum Equipment Suppliers Association in Houston.

Collaboration is an e-commerce development that continues to flourish. A poll of AMR's customer base showed that 58% of oil industry executives said collaboration is "strategically necessary."

The same percentage of respondents agreed that collaboration is one of the few things that companies can do to affect "both the top and bottom line."

An impromptu poll of the PESA audience revealed that many of the IT specialists present were in the process of completing smaller, cost-savings projects rather than full-scale, costly IT projects.

IT spending currently comprises about 2% of oil and gas companies' budgets, Swanton said, and those budgets are expected to rise by only 1% this year.

AMR has found it likely that 7-15% of the IT projects now under way could readily be canceled or delayed, he said. That is because oil and gas companies are holding down overall spending, so IT budgets also are down.

Government Developments

BANGLADESH has insufficient gas reserves to serve domestic and foreign markets, and the government should not authorize exports, the Nagorik committee has said.

It listed Bangladesh's reserves at 6.2 tcf proved and 5.8 tcf probable. The Bangladesh Geological Society and Bangladesh Economic Association formed the seven-member committee in June.

Some of its conclusions are at odds with statements by Unocal Corp., which proposed in late 2001 to export Bangladeshi gas by pipeline to India.

Energy sources other than gas are unlikely to penetrate Bangladesh markets in any significant way in 40-50 years, the committee argued. It called USGS-Petrobangla estimates of undiscovered resources of 8.43 tcf (95% probability) and 32.1 tcf (mean probability) "conjectural" and termed the figures unsuitable for gas utilization policy matters (OGJ, Nov. 18, 2002, p. 24).

Unocal has proposed to build a $500-700 million, 847 mile, 30-in., 500 MMcfd pipeline from Bibiyana gas-condensate field to the Delhi, India, area (OGJ Online, Dec. 7, 2001).

Earlier, Unocal found that the Bangladesh gas market is oversupplied for 5 years, may be saturated indefinitely, could not accept Bibiyana gas for more than 8 years, and could not take the field's maximum production volumes for more than 15 years.

The committee said that Unocal's production-sharing contract contains no provision for export of gas by pipeline. It argued that Unocal's share of reserves is not enough to support such exports and that state Petrobangla's share of gas would also be required.

Unocal documentation, however, noted that the Block 12 PSC "provides for the right, subject to contract conditions, to export gas in the form of LNG and, if LNG is not feasible, to devise an 'acceptable alternate plan.'" Outside engineers assign Bibiyana field proved and probable reserves of 2.4 tcf and 13.8 million bbl of condensate and found that it could hold a further 3.1 tcf and 16.9 million bbl of possible reserves.

The Nagorik committee also concluded that gas consumed in Bangladesh would be of significantly greater economic value to the country than gas exported.

If Unocal were allowed the option to export, the committee said, other international oil companies operating in Bangladesh also would want the same option, hastening depletion. A pipeline that has been built across the Jamuna river was intended to supply gas to western Bangladesh, but this goal would be compromised if the line became part of any export project, the committee noted. Unocal has spoken of a window of opportunity that could close to Bangladesh gas if Middle Eastern LNG or Iranian gas captured Indian markets first.

Meanwhile, at least two operators have reported discoveries of 8-9 tcf of gas in place a few miles offshore in the Bay of Bengal (OGJ Online, Nov. 7, 2002). These finds are as close to Delhi as the Bangladesh gas fields.

Quick Takes

CONOCOPHILLIPS said it expects government approval in 2003 for its planned development of giant Corocoro field in the southwestern Gulf of Paria off Venezuela.

The company said that the block also contains associated gas, and that ConocoPhillips is well positioned to participate in any regional gas initiative in the area.

Oil production would begin in 2005 at a gross 50,000 b/d. Two development stages are envisioned, with first phase reserves of 100 million bbl of oil net to ConocoPhillips's 50% interest. Second phase reserves would go on line in 2007-08, with Phase II to be larger than Phase I in almost every aspect.

The operator said last summer that it determined Corocoro to be commercial and received board approval for development while asking partners and the government to agree that the project is economic and to approve a first phase.

Company documents refer to an "excellent appraisal program" consisting of four wells drilled last spring in the northern Greater Orinoco Delta region.

The Corocoro 1X discovery well in 8 ft of water found oil in three zones and gas-condensate in a fourth zone. TD was 12,100 ft (OGJ, Mar. 29, 1999, p. 30).

Other interests in the Gulf of Paria West block are Agip Venezuela BV 40% and Taiwan's Chinese Petroleum Corp. unit Overseas Petroleum & Investment Corp. 10%.

A group of leading deepwater operators and service-supply companies has selected Aker Kværner to execute Phase VI of the Deepwater Staged Recovery (DeepStar) project in the Gulf of Mexico. DeepStar was initiated in 1992 to develop economically viable, fit-for-purpose, deepwater production technology with global applicability to accommodate development in deeper water, smaller fields, and deeper formations (OGJ, Sept. 2, 2002, p. 32). In addition, DeepStar seeks to develop technology to recover more oil and gas from already discovered fields. Phase I was completed this spring (OGJ Online, Apr. 25, 2002). Aker Kværner's contract calls for conducting a systems engineering effort, including technical and economic studies necessary for DeepStar to evaluate new technology scenarios and identify elements needed to make accessing these smaller deepwater reservoirs economical. Aker Kværner's engineering resources in Houston will develop the "Techno-Economic Evaluation of Marginal Fields" study based on three fictitious reservoirs that represent what is believed will be the most likely deepwater reservoir sizes: the Gulf of Mexico in 5,000 and 10,000 ft of water and West Africa in 5,000 ft of water.

CHINA'S FIRST LNG project, which involves the construction of an LNG import terminal and high-pressure gas pipelines, got a boost Nov. 25 when the North West Shelf (NWS) venture participants signed purchase and supply agreements with the Guangdong LNG project companies for LNG from the NWS off Western Australia.

The agreements signed by the six NWS LNG sellers in Phase I of the project cover the supply of 3.3 million tonnes/year of LNG for 25 years starting in late 2005. The contract is valued at $20-25 billion (Aus.).

Phase I construction in China includes the grassroots LNG receiving terminal and regasification plant and 300 km of pipeline on the eastern side of the Pearl River delta in Guangdong Province. A lateral also will be built to deliver natural gas to Hong Kong.

The contract also requires additional LNG processing facilities and a second trunkline from the North Rankin A platform to shore in Western Australia.

Three existing processing trains at the Karratha LNG liquefaction plant on the Burrup Peninsula produce a total of 7.5 million tonnes/year of LNG, and construction is under way on a fourth, which alone will have a capacity of 4.2 million tonnes/year of LNG. First LNG from the fourth train is scheduled for mid-2004.

A fifth LNG liquefaction train at Karratha, which will require expenditures of more than $1 billion (Aus.) over 3 years, also is being designed, said John Akehurst, managing director for NWS operator Woodside Energy Ltd. (OGJ Online, Aug. 14, 2002). The facility's fourth LNG train and a second natural gas trunk line from the fields, also under construction, will cost $2.4 billion (Aus.). Completion of the fourth and fifth trains will more than double Karratha's current LNG processing capacity.

Phase II of the China construction, planned to start in 2008, is an extension of the pipeline around the western side of the Pearl River delta. Regasified LNG will be supplied to electric power generation plants and city gate distributors in Guangdong Province and in Hong Kong. Total cost for both phases is $850 million.

In addition, two or three new LNG transport vessels will be required to service the China trade route. A fleet of eight LNG ships currently serve the NWS project, and a ninth vessel is under construction by Daewoo Corp. in South Korea.

"It is proposed that (NWS) and the Chinese shipping companies, Cosco and China Merchants, will establish a joint venture company to support LNG transport to Guangdong," said Woodside Energy.

China National Offshore Oil Co. heads up the Guangdong LNG project with a 33% shareholder interest. BP Global Investments Ltd. 30%, and Guangdong entities 31% and Hong Kong parties 6% make up the balance.

CNOOC Ltd., CNOOC's offshore oil and gas producing unit, will have the opportunity to acquire a participating interest in the NWS reserves and production that will supply gas to Guangdong.

BG Group PLC received approval in November to construct and operate a 330 million euro LNG terminal in Brindisi Port, on the southeast coast of Italy. BG said it expects to sanction the project by yearend 2003. The Brindisi terminal, which will be constructed in two phases and operated by BG, is expected to be operational by yearend 2006, BG said. Phase I will be designed with throughput of 3 million tonnes/year of LNG. Phase II will double this capacity. The terminal's location on the Mediterranean Sea is in close proximity to areas of high power demand in the Puglia region, BG said, and is within 5 km of Snam Rete Gas's 29,600 km natural gas pipeline system. Italy's energy demand continues to rise, with forecasts for 2010 expected to reach levels 25-30% higher than current demand, BG said. Currently, the country is a net importer of natural gas and has one LNG receiving terminal in operation on its northwest coast. Preliminary front-end engineering design work has been conducted on the terminal and work to finalize the plant's design is under way, BG said.

AMERADA HESS CORP. reported Nov. 26 that its G-13 wildcat well drilled on Block G in the Rio Muni basin off Equatorial Guinea encountered 251 ft of net oil pay over a 963 ft interval.

The well was drilled in the southern part of the block 10 miles south of Ceiba field. Wireline sampling recovered 34-37° API gravity oil and indicated good reservoir characteristics, the company said. The well lies in 3,284 ft of water, and its TD was 13,737 ft. After technical review and evaluation, Amerada Hess said it would drill an appraisal well in 2003 that also will explore deeper objectives.

"This well in the southern toe thrust is an important discovery in a previously undrilled area of Block G that may be a significant new oil fairway," said Brian Maxted, senior vice-president of global exploration. "We will appraise this discovery in 2003 after drilling exploration wells on several other prospects (on) Block G and adjacent Block F."

Amerada Hess is operator and has an 85% working interest in both Blocks G and F. Its partner in the blocks is Energy Africa Ltd. of South Africa, which has the remaining 15%. The government of Equatorial Guinea has a carried 5% interest in Ceiba field production and will have a carried 5% participating interest in any production from this discovery in southern Block G.

In early September Amerada Hess struck pay in the eastern portion of Elon field on Block G in 165 ft of water, encountering 316 ft of net oil pay in a single, continuous column and confirming the Elon G-8 discovery reported earlier this year, Amerada Hess said (OGJ Online, June 19, 2002).

Petroecuador, Ecuador's national oil firm, is offering four Pacific Coast blocks in the Gulf of Guayaquil region for exploration and development under its ninth international bidding round, government representatives and company officials said Nov. 20 in Houston. Blocks 39 and 40 are offshore in 10-2,000 m of water. Block 5 is primarily onshore with a small section extending into the gulf. Block 4 includes land on the southeastern tip of the mainland, a portion of the adjacent Puna Island, and shallow gulf waters of 10 m or less. Ecuador officials plan to open a data room on the four blocks Dec. 9, and bidding will close Apr. 25, 2003. The participation contracts being offered provide a 4-year exploration period for oil and a 5-year period for natural gas, with possible extensions of 2 years each in which to develop a market and construct a pipeline infrastructure for any gas found. Exploitation periods under the participation contracts are 20 years for oil and 25 years for gas, with possible extensions for both under certain conditions.

Australia's BHP Billiton Ltd. said the Shenzi discovery well in the deepwater Gulf of Mexico has encountered a 465 ft gross hydrocarbon column with 140 ft of net pay. The discovery well, which was drilled 125 miles off the Louisiana coast on Green Canyon Block 654, is in the Western Atwater Foldbelt area where BHP Billiton previously discovered oil and natural gas at Mad Dog, Atlantis, and Neptune (OGJ, Nov. 5, 2001, p. 84). The Western Atwater Foldbelt is set to become a core producing area for BHP Billiton starting in late 2004, a spokesman said. BHP Billiton operates Shenzi and owns 44%, while BP PLC and Amerada Hess Corp. each hold 28% interest. Appraisal drilling will be necessary to determine the size of the find and the significance of the well, BHP Billiton said.

TEPPCO PARTNERS LP plans to expand the capacity of its northeastern US LPG delivery system next year by more than 1 million bbl during peak winter months, the company reported. TEPPCO will construct three new pump stations on its LPG common carrier pipeline between Middletown, Ohio, and Greensburg, Pa., completing the expansion during third quarter 2003.

TEPPCO said the project is part of a system-wide effort to increase its LPG deliverability to meet rising demand, and to that end has completed an LPG truck rack upgrade at Princeton, Ind., and will add an additional 3.5 million bbl of brine containment at Mont Belvieu, Tex., by summer 2003.

Houston-based analyst Purvin & Gertz Inc. reported in June that demand for LPG is expected to increase by 2005 to more than 67 million tonnes/year from more than 40 million tonnes of LPG in 1985 (OGJ, June 24, 2002, p. 58).

The Federal Energy Regulatory Commission has approved Charlotte, NC-based Duke Energy Corp.'s Patriot natural gas pipeline. The approval gives Duke's East Tennessee Natural Gas (ETNG) subsidiary authorization to construct, own, operate, and maintain pipeline and related facilities along its existing ETNG system in Tennessee and Virginia and extend the system into southwest Virginia and northern North Carolina, where it will supply natural gas to new electric power plants. Peak electric power demand in the Virginia-Carolinas area is projected to grow 2.3%/year through 2010, reported a study completed earlier this year by energy consulting firm Merrimack Energy, Salem, NH (OGJ Online, Feb. 25, 2002). The Patriot extension will consist of 94 miles of 24-in. pipeline from Virginia to North Carolina. It will deliver natural gas for the first time to parts of southwestern Virginia and introduce a competitive supply of gas to North Carolina from Appalachian and Gulf Coast producers (OGJ, Feb. 4, 2002, p. 69). The line would originate from Duke's East Tennessee system in Wythe County, Va., cross Carroll, Patrick, and Henry counties in Virginia, and terminate in Rockingham County, NC. About 7 miles of lateral line would run from Rockingham County to Henry County, Va.

CNOOC and Shell Petrochemicals Co. Ltd. (CSPC) awarded a contract to Technip-Coflexip in a joint venture with Chiyoda Corp. and Mitsubishi Corp. of Japan for the engineering, procurement, and construction of a world-scale petrochemical complex at Huizhou, Guandong Province in southern China.

The complex will produce 560,000 tonnes/year of styrene monomer, 250,000 tonnes/year of propylene oxide, 135,000 tonnes/year of polyols, 60,000 tonnes/year of mono-propylene glycol, and 320,000 tonnes/year of mono-ethylene glycol.

The project is a part of CSPC's $4.3 billion Nanhai petrochemical project, one of the largest Sino-foreign joint venture projects in China (OGJ Online, Nov. 6, 2002).

Engineering for the project will be executed in Kuala Lumpur by Technip Malaysia and in Shanghai by Technip Tianchen.

The plants are expected to be on stream by the end of 2005, producing about 2.3 million tonnes/year of products and generating as much as $1.7 billion in products sales, primarily supplying customers in Guangdong and the high consumption areas of China's coastal economic zones.