If Saudi Aramco's $7-billion (U.S.) Khursaniyah oil project had come on stream at the end of 2007 as scheduled, the world economy might not be staggering under $135 crude prices.
The planned 500,000 barrels a day of Khursaniyah production would have been like a cool drink of water for an oil market thirsting for additional supply.
Instead, the project was stalled by delays in the construction of a processing plant needed to treat the natural gas liquids that Khursaniyah would produce along with the light, relatively sweet crude oil.
Not far from Khursaniyah, in the eastern part of the kingdom, the state-owned oil monopoly, Saudi Aramco, is spending $17-billion to develop the vast Khurais field.
That project aims to add one million barrels a day of crude oil by the end of 2009, but analysts question whether the complicated project - which requires tremendous amounts of sea water to be injected into the reservoir to produce the oil - will meet a demanding construction deadline.
Even in Saudi Arabia, where oil is more plentiful than water, getting the next barrels out of the ground is becoming an increasingly expensive and complex undertaking.
From the Middle East to the U.S. Gulf of Mexico to the Canadian oil sands, project delays and skyrocketing costs have become epidemic in the global oil business. And as a result, the industry has had a hard time bringing on new capacity to meet demand growth that is fuelled by the booming emerging markets like China, India and the Middle East itself.
The industry faces a daunting set of challenges: Companies are increasingly forced to target unconventional resources like oil sands and deep water fields; years of underinvestment left drilling and oil field construction sectors unprepared for the current boom; the work force is aging; and material costs and bottlenecks are rising throughout the global infrastructure sector.
"If I had to single out what is the one key problem that is impeding the world's ability to expand oil supply, it's this slippage in new projects," David Fyfe, senior supply analyst for the Paris-based International Energy Agency, said in an interview.
Next weekend, ministers from top producing countries and major consumers will meet in Saudi Arabia to discuss how to cool off oil markets that have sent prices to record levels that were virtually unimagined a year ago. The stunning runup in crude oil has ignited inflation and contributed to an economic slowdown that is compounded by the credit crunch and housing market slump in the U.S.
(Canada, despite being the largest source of imported oil for the largest consumer on the planet, will not attend the meeting in Saudi Arabia.)
Facing unrelenting pressure from the U.S. government to boost production and ease soaring crude prices, Saudi Oil Minister Ali al-Naimi recently said the Khursaniyah project had begun to pump small volumes of oil.
An unsourced report in the Middle East Economic Survey yesterday suggested the Saudis will promise an increase in production of 500,000 barrel a day at the meeting, likely by announcing the full startup of Khursaniyah. The additional Saudi supply - combined with weakening global demand - would likely be enough to relieve some pressure from overheated markets.
But few analysts expect oil prices to drop below $100 a barrel over the next year.
In trading yesterday on the New York Mercantile Exchange yesterday, the benchmark West Texas Intermediate settled at $134.86 a barrel, down $1.88 on the day. While off from the record $138.54 hit last Friday, the Nymex price is still more than double its year-ago level of $66.65 a barrel.
As crude prices climbed inexorably through the first half of this year, U.S. politicians blamed the Organization of Petroleum Exporting Countries for restraining supplies, while OPEC ministers pointed the finger at speculators who, they say, are driving up prices beyond what is justified by market fundamentals.
The IEA, which represents rich consuming countries, has fingered another culprit: chronic underinvestment across all aspects of the industry - from construction of drill rigs that explore for the resource, to the development of new sources of crude, to the updating of the refineries that process it.
"The underlying problem is that we continue to have undercapacity across the entire oil value chain," IEA president Nobuo Tanaka said in a presentation in Tokyo last week,
At the same time, oil companies - both state-owned and the multinationals - are forced to develop increasingly more complex and technically challenging projects in the absence of the "low hanging fruit" of easily accessible new conventional oil fields. As they take on such major construction projects, the oil companies are operating in a booming international infrastructure market, where engineering, labour and materials are in short supply and costs are rising dramatically.
As a result, projects that would be adding supply to the market are facing bottlenecks and cost overruns.
The IEA reports that OPEC's effective surplus capacity will hit two million barrels a day later this year, and could drop to as low as one million barrels by 2012. That's a dangerously low margin in an industry that faces frequent disruptions, ranging in the past from hurricanes in the Gulf of Mexico, to pipeline ruptures in Alaska, to strikes in Nigeria. A constant source of concern is the ever-present fear of geopolitical strife in the oil-rich Persian Gulf region.
So far this decade, OPEC's spare capacity has been closer to three million barrels a day, and averaged between 3.5 million and four million in the 1990s.
At the same time, non-OPEC sources of new supply have become increasingly costly to produce. In the Canadian oil sands, and Venezuela's extra-heavy oil belt, the break-even point for new oil supplies is approaching $65 a barrel.
Average finding and development costs for international oil companies have more than tripled since the beginning of the decade - from $6.08 a barrel to $19.09, according to a survey by PFC Energy, a Washington, D.C.-based consultancy.
"Oil companies are paying a lot more for service, across the board," PFC analyst David Kirsch said. "At the same time, you're seeing a tremendous backlog in the service company workloads. So even if you have the money for a new project to come on line, you have to wait."
The rising costs and production challenges are among the factors driving prices, Mr. Kirsch said, as speculators bet that markets will remain tight and that tomorrow's barrel of oil will cost more to produce than yesterday's did.
"It certainly is a significant element of what's driving prices," he said. "It's just much harder to produce this stuff and there is a recognition now that your marginal barrel - which is coming from places like the [Alberta]tar sands - is around $65 a barrel."
While prices have climbed well beyond levels that justify new investment, oil companies have been slow to respond.
In part, that's because OPEC's state-owned oil companies control a growing share of the market and are less interested in making multibillion-dollar investments that will drive down prices. In part, it's because international oil companies endured market crashes in both the 1980s and the 1990s and have been wary about whether the sharp price increases of the past three years will endure.
And in part, it's because the prospects simply are not as attractive as they once were. British-based BP PLC this month agreed to spend $1.2-billion (Canadian) to develop three parcels in the Beaufort Sea, where one well can cost more than $60-million, where ice conditions are hazardous and rapidly changing, and where there are no pipelines to move to market any oil or natural gas that it might find.
"People are looking at the oil companies and they're looking at huge profits and are forgetting the amount of investment the oil companies now need to do if they are going to be able to meet the world's energy demand," said Candida Scott, senior director for cost and technology at Cambridge Energy Research Associates.
Output: 1.766 million barrels a day.
Reserves: 11 billion barrels. In addition, state-owned Petroleo Brasileiro SA (Petrobras) has estimated recoverable reserves at its new Tupi field of up to eight billion barrels, one of the largest discoveries in the past 20 years. And there are estimates that the Santos, where Tupi is located, could contain as much as 33 billion barrels of recoverable reserves.
The plan: Aggressive exploration and development of offshore fields to boost production from 1.77 million barrels a day to several million barrels a day by 2020.
The challenge: While Brazil is increasing its production from near-shore finds, the major discoveries lay hundreds of kilometres offshore, in extremely deep water. They occur some two kilometres under rock, sand and salt beds, in formations that include salt. The recovered oil must also be shipped by pipeline or tanker from well site to shore.
Technology: Petrobras may be buying as many as 17 new drill ships and semi-submersibles for development of the Tupi and Carioca fields alone. The company is still developing the technology needed to extract the oil from the rock under more than 1,000 metres of salt formation.
Cost of technology: Swiss investment bank UBS has estimated it could cost a staggering $600-billion (U.S.) to develop the two major subsalt fields, Tupi and Carioca.Companies: Petrobras is the principal operator/investor. Others in Brazil's offshore include Norway's StatoilHydro ASA, Britain's BG PLC, Spain's Repsol YPF SA, and U.S.-based Exxon Mobil Corp.
The results: Brazil is currently experiencing an oil-related boom as drilling ships and foreign companies flock to Rio de Janeiro to participate in the Santos basin activity. The recent finds have raised the possibility that the country could become a major non-OPEC source of crude oil exports, eclipsing Venezuela as the South American oil powerhouse. However, analysts warn that even if the optimistic estimates of reserves are firmed up, it will be tremendously costly to recovered the oil, and that flow rates from the untested subsalt formations may be disappointing.
Output: More than 700,000 barrels a day from Alaska, but production is declining as fields mature.
Reserves: No one knows, because the region is sparsely explored. Estimates suggest huge, untapped deposits of oil and gas in waters north of Russia, Scandinavia and Canada. Alaska is estimated to hold 35 trillion cubic feet of natural gas, while the Northwest Territories holds six trillion cubic feet, as well as 2.8 billion barrels of oil.
The plan: Develop massive pipelines to stranded gas assets, such as the Mackenzie Valley and Alaskan gas reserves, while exploring for oil and gas under the Arctic ice cap, bringing those resources to market.
The Challenge: Extreme cold, sparse population, bereft of infrastructure.Extremely expensive to carry out exploration and development. But sky-high oil and gas prices are prompting companies to take a closer look at how they might exploit the North. Even at these prices, however, many are concluding there is more economic opportunity in balmier climes.
Technology: Offshore oil or gas drilling must cope with frozen seas, which would impede transportation. Unstable permafrost can threaten infrastructure, such as pipelines. Companies may look at production techniques that operate wholly underwater, such as the subsea production system developed by Norwegian firm StatoilHydro.
At Snohvit, an LNG export plant in the Barents Sea, StatoilHydro pipes gas from the ocean floor directly to a plant on the northwest Norwegian coast, instead of using a fixed or floating offshore platform to collect the gas. Must withstand extremely harsh conditions.
Cost of technology: Building an Alaska gas pipeline carries a price tag of $30-billion (U.S.), which would make it the most expensive private sector project built in North America. The Mackenzie Valley gas pipeline is expected to cost more than $16-billion (Canadian). Rough estimates suggest that the costs of producing a barrel of crude from the Arctic could be well over $60 (U.S.) a barrel.
Result: Alaska had made plans to get its gas out of the ground and down to southern markets in the 1970s. Thirty years on, that is still just a pipe dream, and any completed project is believed to be still at least a decade away. Producers such as BP PLC and ConocoPhillips Inc. are spending $600-million on preliminary pipeline work, while TransCanada Corp. is seeking government approval for a rival project. Only one, if any, will succeed.
VenezuelaOutput: 2.5 million barrels a day.
Reserves: 80 billion barrels of oil, and as much as 270 billion barrels of extra-heavy crude or bitumen in the Orinoco belt, an area in northern Venezuela similar to Alberta's oil sands.
The plan: To increase its production through development of extra-heavy Orinoco oil resources.
The challenge: Venezuela used to produce well over three million barrels a day, but output has fallen since workers at Petroleos de Venezuela SA (PDVSA), the national oil company, called a strike in 2002. More than 18,000 workers left PDVSA after the strike, leaving Venezuela without the expertise necessary to keep production rates level. After years of exploitation, the crude in conventional oil basins is becoming depleted. The challenge in the Orinoco belt is similar to Alberta's oil sands; the oil is heavy, and difficult to extract, transport and refine. Since it's not as attractive to refineries, it fetches a cheaper price than lighter crudes.
Technology: To maintain output rates and extract from deeper conventional reservoirs, natural gas must be injected. To develop the Orinoco belt will take billions of dollars more in investment in pipelines, steam injection wells, upgraders and other facilities necessary to produce extra-heavy crude.
Cost of technology: Venezuela needs to spend at least $3-billion (U.S.) at existing oil fields - on gas reinjection, water drainage, monitoring, and other maintenance measures - just to maintain production at current levels. To produce a barrel of crude from the Orinoco belt costs between $30 and $40.
Companies: PDVSA; foreign national oil companies from Brazil, Iran, China and India; Total, StatoilHydro, Chevron Corp., BP.
The struggle: Producers are leery of further changes in the country's royalty structure; last year, Venezuela completed a long-running battle to increase PDVSA's stake in oil projects operated by foreign companies. As a result, Conoco and Exxon left the country altogether in protest. Venezuela's continuing spats with the U.S. do little to engender the confidence of big business. Is there enough crude left in Venezuela to make it worthwhile for companies to do business with President Hugo Chavez?
Alberta oil sands
Output: 1.3 million barrels a day.
Reserves: 173 billion barrels.
The plan: To boost output to around four million barrels a day by 2020, and eventually to as much as eight million.
The challenge: Oil sands production is rising as high prices make the resource more economic. But the boom means there are not enough workers or materials to go around, forcing up wages and prices. Alberta's crude is mixed with sand, which makes production technically complex and more energy-intensive than conventional oil extraction. The oil is so heavy that it won't travel down a pipeline without being diluted or treated, so companies must spend money either processing the bitumen or adding diluent to make it more fluid. As awareness of the oil sands' environmental impact grows, regulators and the environmental lobby are running a fine tooth-comb over every new project application - creating more potential delays.
Technology: Steam must be injected into deep crude reservoirs to create mobility, a process called steam-assisted gravity drainage or SAG-D. Then, vast upgraders are needed to process the oil before it can be refined. New technologies, such as partial underground upgrading, horizontal combustion and innovative solvents, are being developed and could make extraction cheaper and easier.
Cost: Building an integrated oil sands project costs around $100,000 a flowing barrel. To produce a barrel of upgraded oil sands crude using SAGD costs more than $60 a barrel, in comparison to around $40 for a barrel of conventional Albertan crude (excluding royalties).
Companies: Almost every major publicly traded oil company in the world has some holdings in Alberta, including Royal Dutch Shell PLC, BP, Conoco, Total and Chevron. Canadian players include EnCana, Nexen, Canadian Natural and Husky Energy.
Result: Syncrude Canada - Canada's largest oil project - is still struggling to integrate the 100,000-b/d expansion it completed two years ago at a cost of $8.4-billion. New apparatus installed in the plant - intended to reduce the amount of sulphur in emissions - didn't work properly and released too much ammonia into the surrounding atmosphere. Since then, Syncrude has struggled to get to grips with the malfunctioning unit, resulting in millions of dollars in lost revenues.
U.S. Gulf of MexicoOutput: 1.2 million barrels of oil a day, eight billion cubic feet of gas a day.
Reserves: Estimates of how much crude the Gulf's ultradeep regions (over 1,200 metres), so far untapped by drillers, may hold range from three billion to 20 billion barrels of oil.
The Plan: Led by Chevron, BP and StatoilHydro, companies are beginning to look at bringing the ultradeep fields on stream; Chevron expects its Jack field to produce 60,000 barrels of oil a day by 2013.
The Challenge: Existing fields are aging, leading to production declines. Substantial damage to regional infrastructure by hurricanes Katrina and Rita also caused marked production declines. The ultradeep drilling required to bring the Jack field and others on stream is expensive, because the drill bit has to travel a large distance before hitting rock. It's also riskier; the deeper a company gets, the harder it is to get accurate geological findings that will tell it where to drill. So while the rewards are great, it's also easy to make an expensive mistake.
Technology: Many shallow water exploration and production techniques don't work in deep water because of the water pressure, as well as differences in geology and salt layering. New exploration methods, such as subsalt imaging, which unscrambles sound waves sent haywire by the salt layers, are being developed.
On the production side, companies are investigating ways to separate oil, gas and water in the wells themselves or on the sea floor, rather than doing that work on a floating production vessel, to prevent waste materials having to be pumped the long distance to the surface.
Cost of technology: The added depth adds to the cost. While it costs around $1-million (U.S.) a day to hire a rig to explore in shallow water, Chevron is spending about $1.6-million a day for a deep-water drill ship to work on its Tahiti prospect; it costs around $200-million to drill a single well in the area. Analysts estimate that to produce a barrel of crude from the ultradeep area would cost above $50 a barrel.
Companies: Many U.S. firms, including Chevron, Exxon, Conoco and Amerada Hess Corp., as well as foreign explorers like BP, Royal Dutch Shell and Total SA The example: Chevron's Jack prospect is expected to cost $3-billion to produce, but it's been hard for the company to find rigs capable of drilling at such great depths; there are fewer than 40 in the world, stalling crucial exploratory work.
In millions of barrels a day
|Alberta oil sands||1.3|
|U.S. Gulf of Mexico||1.2|
SOURCE: THE GLOBE AND MAIL RESEARCHReport Typo/Error