IN THE PAST three or four years, the term “stranded gas” has come into vogue to describe discovered but undeveloped gas reserves of at least 2,000 trillion cubic feet (cf) worldwide. The term often carries the implication that the gas is not only remote, but also mainly in small deposits. It is frequently used, therefore, to promote the prospects for small-scale Fischer-Tropsch gas-to-liquids (GTLs) plants.

There are about 800 small, undeveloped fields that are potential candidates for GTLs projects of up to around 10,000 barrels a day (b/d). Methanol projects may also be of growing interest to utilise small deposits, if markets develop for methanol’s use as a principal source of hydrogen for automotive fuel cells.

However, at least half of the undeveloped reserves are in about 70 fields of over 4 trillion cf. With reserves of 4 trillion cf, it may become commercial to invest in a comparatively large and, therefore, much more economic GTLs plant. Alternatively, such reserves are sufficient for a single-train liquefied natural gas (LNG) plant. But while the size of a single field’s reserves is important, successful export projects can be based on gas gathered from more than one field.

Field size: only part of the story
Factors that cast discovered reserves into the category of stranded are numerous, and only partly rest on field sizes. They include:

• An existing surplus of potential supply to the field’s feasible markets;

• The field is “remote”. Its distance from potential markets is such that the delivered costs of the gas would be too great to be competitive;

• The field is landlocked in a country with a small gas market and at a great distance from any coast where an LNG export terminal could be built; and

• The field is too small to justify investment in facilities of economic scale to market it.

Most stranded reserves are in fields that are totally undeveloped. There are about 1,200 such fields worldwide, roughly half of which are onshore and half offshore. However, about two-thirds of the onshore fields are comparatively small – up to 0.6 trillion cf.

Offshore drilling results, meanwhile, are generally classified as discoveries only if they are of potentially commercial size. Because they are usually – though not always – more costly to develop than onshore fields, the typical size of announced discoveries is much greater. Of about 600 undeveloped offshore fields, 30 are estimated to exceed 4 trillion cf in size, holding aggregate proved and probable reserves of more than 460 trillion cf, or an average of some 15 trillion cf.

In addition to reserves in fields that are wholly undeveloped, there are substantial undeveloped reserves in partly developed large fields. In a highly competitive market, these may be of primary importance, as there is usually considerable cost saving because of the possibility of sharing established infrastructure. This gives such gas reserves a head start over totally undeveloped fields to find market outlets as soon as the forecast demand growth justifies investment in additional supplies.

Qatar holds a unique status
A prime example of this circumstance is the giant North Field in Qatar. The existing and planned capacities of Qatargas and Rasgas for LNG exports can be estimated on the basis of 25-year operations, requiring gas supplies totalling about 31 trillion cf.

At the same time, Qatar Petroleum is making a major commitment to the development of GTLs projects. It is already engaged in a 51:49 venture with Sasol/Chevron for construction of a 34,000 b/d GTLs plant. And a special GTLs committee is studying five proposals for GTLs plants made by other companies – ExxonMobil, Shell, Conoco, Syntroleum and Ivanhoe.

If all these proposals were implemented, on the basis of 25-year operating lives, together with the Sasol/Chevron plant, they would require an estimated 20 trillion cf of gas supplies. This estimate depends on assumed plant sizes, but it gives a guide to the significance of Qatar’s potential.

The reserves that would be committed for LNG and GTLs on the above estimates would total as much as 50 trillion cf, but would account for about 12% only of the country’s estimated total reserves of some 400 trillion cf.

A lack of market prospects is a principal factor causing large gas reserves to remain undeveloped in several countries. For example, there are around 26 trillion cf in Alaska’s North Slope field. Three alternatives to commercialise these reserves have been studied:

• A long-distance, big-inch pipeline to supply the US Midwest;

• A shorter pipeline to Kenai and an LNG export plant, to supply Asian markets; and

• A GTLs plant, with the synthetic crude output transported through the TransAlaska oil pipeline.

Until recently, the construction of a long-distance pipeline to serve US markets was favoured by both ExxonMobil and BP, which hold respectively 9.6 trillion cf and 6.9 trillion cf of North Slope reserves.

The alternative of LNG exports was favoured by Phillips, holder of 9.5 trillion cf and 70% owner of the existing small LNG plant at Kenai.

However, some time ago, BP declared its opposition to the LNG export proposal on the grounds that there is surplus supply in Asian markets. And it seems both BP and ExxonMobil have turned their backs on the alternative to pipe the gas to US markets – prospective long-term US market prices are not expected to be high enough to make such a project profitable for several years.

No new word has yet emerged on whether GTLs plants may provide a solution to utilising North Slope gas. But even while the pipeline and LNG projects were under study, BP had already indicated that there would be enough North Slope gas to start up a GTLs plant by 2007. BP says the capacity under consideration for the plant is between 30,000 b/d and 85,000 b/d.

Australia’s abundant reserves
The issue of markets for undeveloped gas creates a problem of even greater magnitude offshore Western Australia and Australia’s Northern Territory. According to a report issued by the Australian Department of Industry Science and Resources’ GTLs Task Force, Australia’s proved and probable gas reserves in these offshore areas are estimated at around 108 trillion cf (an additional 7.5 trillion cf is estimated for the Gippsland Basin, off New South Wales).

These are mainly in very large fields, and at water depths ranging from 100 metres to as much as 1,200 metres.

The total of about 108 trillion cf comprises 85 trillion cf off Western Australia (61 trillion cf in the Carnarvon Basin and 23.7 trillion cf in the Browse Basin) and 23 trillion cf off the Northern Territory. The last of these includes estimates – of about 12 trillion cf – is for the Bayu-Undan field and the Greater Sunrise fields, which lie partly in waters recently designated as belonging to newly independent East Timor. The estimates are tentative figures partly based on results of a very small number of wells; but they indicate the scale of the problem.

Commitments and proposals for existing and planned gas-consuming projects in Australia – principally LNG exports – are expected to absorb about 45 trillion cf over 25 years (PE 4/02/ p19). Thus, more than 60 trillion cf, or some 60% of estimated existing reserves, are effectively stranded.

Like Qatar, Australia can be seen as waiting for markets to grow or new markets to develop. The US west coast, in particular, may provide a promising new market. This was indicated by a Phillips’ agreement with El Paso – since abandoned – to ship gas from Bayu-Undan, across the Pacific, to Baja California, in Mexico. But further gas exports may be constrained, because the gas is comparatively costly to develop and not as well located geographically in relation to potential markets.

In these circumstances, it is appropriate that the federal government is giving strong backing to GTLs projects to make supplies to the fast-growing markets for automotive diesel throughout Asia.

Releasing gas in Latin America
In the wake of privatisation of Bolivia’s oil and gas industry, a dramatic increase in exploration success has increased its estimated reserves sharply from a mere 4 trillion cf four years ago to 40 trillion cf. These are mainly in four fields. Two fields, operated by Petrobras, are exporting to Brazil. The operators of the other two fields, however, with reserves so far estimated at 13 trillion cf (Margarita) and 9 trillion cf (Itau) are anxiously eyeing the possibilities of making LNG exports to Mexico and on to the US west coast.

But Bolivia is landlocked. Exports using a terminal in another country would raise control and jurisdictional problems and, in the case of a terminal in Chile, possibly political problems also. The alternative is an export terminal in Peru, but this would need a longer pipeline and therefore be more expensive. And Peru has its own ambitions for LNG exports to the same markets.

It is expected that an assessment of Bolivia’s gas reserves, which is about to be completed by De Golyer & McNaughton, will announce an increase in proved and probable reserves to as much as 60 trillion cf. If so, this will further underline the urgency of finding markets for very large quantities of undeveloped gas lest they too enter the category of stranded.

Peru’s problem with undeveloped gas is similar to Bolivia’s. Its gas can be transported to an export terminal near Lima, but would require a 700-km, big-inch pipeline. Originating in the Camisea fields, in a jungle region in Cuzco department, the line would have to cross the Andes and would cost at least $400m.

Camisea reserves are estimated at over 13 trillion cf, lying in two fields, Cashiara and San Martin. Until now they could undoubtedly be regarded as stranded, having been abandoned by Shell and Exxon in 1998, when these companies – after spending $250m on development work – could not reach a satisfactory agreement with the government on terms for domestic gas marketing.

Bayu-Undan exports may be constrained by high
development costs and their remote location from
potential markets

The hope now, is that a newly announced LNG proposal will succeed. This is led by Hunt Oil, with the Argentinian firm, Pluspetrol, as operator of the Camisea fields. Also participating is South Korea’s SK (a partner with Hunt in TotalFinaElf’s LNG project in Yemen, which will take supplies through a 300-km pipeline from the Marib fields). Hunt has appointed Kellogg Brown & Root to carry out a front-end engineering and design study for an LNG plant of at least 4m tonnes a year, requiring gas supplies of 545m cf/d. The study is due for completion within eight months.

The project stands a much better prospect of realisation now than a similar venture would have done four years ago. When Shell and Exxon pulled out, it would have taken a very far-sighted planner to anticipate the possible impact of a growing deficit in US gas supplies creating a potential market for Peruvian exports.

Transport costs the key
In studying remote undeveloped gas, attention tends to focus on LNG and GTLs, as so much of these stranded reserves can be brought to market only by ocean transport. One of the most significant exceptions is the large undeveloped reserves estimated at 300 trillion cf in Russia.

Most of these require long-distance overland pipelines to reach markets. There are, for example, undeveloped reserves estimated at 130 trillion cf in the remote and extremely inhospitable fields in the Yamal Peninsula. But completion of the necessary pipeline and development of the fields have so far proved too expensive to undertake.

Long-distance pipeline costs are factors in gas development for several other countries and high transport costs are a prospect for the 4,000-km pipeline to be constructed to the east China seaboard from the remote Tarim Basin in western China. China’s growing gas demand is also likely to be met by long-distance pipeline supplies from Russia and Kazakhstan.

In the context of these and similar developments elsewhere, increasing attention is being directed at new technology and new techniques to reduce the capital costs of big-inch gas pipelines.

Considerable success towards this aim is being achieved in a research and development programme led by BP – with the collaboration of several pipeline operators and contractors, together with a number of specialist firms. BP claims that after four years work, capital cost reductions of more than 15% are attainable.

Within the next two to three years the company expects to increase this potential saving to more than 25%.

There can be no doubt that a significant element in efforts to develop and market stranded gas will be the industry’s continuing success in reducing gas transportation costs. The major reduction in pipeline costs anticipated by BP has been preceded by equally remarkable reductions in the capital costs of both LNG and GTLs.

The capital costs of liquefaction plants for LNG exports have been cut by 30% by two groups – Shell and Atlantic LNG in Trinidad – and the capital costs of worldscale GTLs plants are expected to be at least one-third lower than estimated two to three years ago.

The importance of politics
While commercial and technological factors are major determinants in plans for marketing undeveloped gas, political considerations must also frequently be taken into account, and sometimes carry more weight. Iran provides an extreme example. The country is still subject to US sanctions on large investments and, as a consequence, it has the world’s largest undeveloped gas reserves outside Russia. Estimated at over 180 trillion cf, these undeveloped reserves include 145 trillion cf in 12 giant fields of over 4 trillion cf.

Fred Thackeray is an independent consultant and writer on the economics of natural gas developments and a frequent contributor to Petroleum Economist. George Leckie is an independent consultant on hydrocarbons reserves. He lectures on oil and gas reserves at the Petroleum Economist’s training course, Fundamentals of the Natural Gas Industry.

Headline: Brazil: no jackpot, yet
Source: Petroleum Economist
Date: May 2002
Author: Tom Nicholls

The areas available for oil and gas exploitation in Brazil are vast and, in most cases, barely explored. The regulator is confident that major discoveries are still to be made and expects the fourth annual licensing round to be a success. But while private oil firms remain optimistic over the longer-term prospects, the confidence of the sector in general would benefit from a big commercial discovery, writes Tom Nicholls

BRAZIL’S FORTHCOMING upstream licensing round is drawing widespread interest from exploration and production (E&P) firms, says the oil and gas regulator.

By the start of last month, 31 firms had paid the participation fee, including eight newcomers, according to Ivan Simões, general manager of licensing rounds at Agência Nacional do Petróleo (ANP). “We are optimistic [about Round 4’s prospects], based on the level of interest companies have shown,” he says. Bidding takes place next month and concession agreements are due to be signed by September.

Several E&P firms confirm they are examining the prospects on offer in June, but most agree that the acreage is less attractive than in past rounds and that future licensings will probably offer more prospective areas. Of greater concern, in any case, is the absence of major commercial discoveries since the upstream sector was opened to competition in the late 1990s.

Brazil’s first licensing round took place in 1999 and there has been one round a year since then (licensing rounds will continue to take place annually, using the same basic format, ANP says). But hopes of quick exploration success have flopped. Most upstream operators and investors agree that, while it is much too early to draw definitive conclusions about the long-term prospectivity of the offshore sector, the lack of exploration success since the market opening in 1997, when Petrobras’ upstream monopoly was formally removed, has been a disappointment.

Nonetheless, there is some encouragement from discoveries by Petrobras and Shell and a number of other finds under appraisal, and generally E&P firms remain optimistic about Brazil’s long-term prospects.

“It is clear to everybody that it is not going to be the bonanza that perhaps people had expected,” says Michiel Kool, vice-president, E&P, Shell Brasil. “A sense of reality is setting in – Brazil’s going to require diligence, technology and hard work like any other province.”

Simões describes the first three rounds as “great successes” and, from the point of view of the ANP and the government, this is undoubtedly true. They attracted investment from many local and foreign firms and generated substantial revenues for the Brazilian treasury (see Table 1).

Range of participants
“We have awarded 67 blocks to 34 companies from 14 different countries,” says Simões, adding that participants range from small, local independent companies to the super-majors, such as Shell, BP and ExxonMobil. “We have also succeeded in attracting investments in a variety of settings, including onshore and offshore basins, shallow to ultra-deep waters, from exploratory frontiers to mature basins.”

ANP has retained this inclusive approach. The fourth licensing round will “provide opportunities for companies of all sizes and shapes, in a variety of environments”. Several blocks are near recent discoveries that are under appraisal. And 28 blocks include, partially or totally, acreage recently relinquished by Petrobras (from the so-called Round 0 – in 1998 ANP granted 58 concessions to Petrobras, covering an area of 456,000 square km, or 7.1% of the country’s total sedimentary areas).

In terms of total area, Round 4, with 144,106 square km on offer (just over 2% of the country’s total sedimentary area), is bigger than each of the previous three rounds. In total, 54 blocks in 18 sedimentary basins are available. Of that, 91,713 square km is offshore (39 blocks – 21 in shallow water, 18 in deep water) and 52,393 square km onshore (15 blocks – nine in mature basins, six in exploration frontiers).

Some companies do not share ANP’s positive view of the acreage on offer in Round 4. Future licensing rounds will benefit from the inclusion of areas from previous licensing rounds as they are recycled under ANP’s relinquishment system. But the first relinquishments from Round 1 are not due until August (and therefore will not be relicensed until Round 5 at the earliest). Jean-Paul Prates, executive director of Expetro, a Brazilian oil and gas consultancy, says: “The impression we get from the industry is that the main blocks are already sold.”

An executive at a foreign oil company says: “The industry, in general, perceives the fourth round as not one of the substantial events in the near term.”

Norm Anderson, country manager for BP Brasil, says BP is examining Round 4’s potential, but claims the fifth, sixth and seventh rounds “may offer up some more-interesting opportunities, as some of the acreage that is currently in private hands begins to become available”.

Petrobras, which bid aggressively and successfully in the first three licensing rounds, consolidating its dominance of the upstream sector, is likely to feature significantly again in June. However, it is keeping its cards close to its chest. “We will look at the opportunities carefully,” says Francisco Gros, the company’s chief executive officer.

Farming in and farming out
Some companies may avoid bid rounds and pursue growth by trying to negotiate farm-in agreements with firms that already own acreage. Prates predicts this will become increasingly popular as a way of expanding in Brazil’s upstream sector. Several firms with larger portfolios (pre-mergers) or holding 100% ownership of blocks are said to be looking for opportunities to farm out acreage. These include: ExxonMobil, ChevronTexaco, Agip, Phillips, PanCanadian, Wintershall and, of course, Petrobras.

Table 1: Brazil's licensing rounds 1, 2 and 3

“The fourth round will compete with farm-outs,” says Prates. “[Farm-outs] are a good way [of acquiring acreage]. In some cases, this may be a better way of getting in [than bid rounds] – it is cheaper and with areas that are better known.” Other advantages include the possibility of negotiating a price (as opposed to blind bidding) and that the licensed area would almost certainly be nearer the drilling phase.

Enterprise is looking for farm-in opportunities, following its acquisition of a stake in Petrobras’ Bijupirá and Salema fields, in March 2000. John Martin, business manager, Enterprise Oil do Brasil, says: “We have aspirations to grow beyond this in Brazil and an important activity is looking at the farm-in market. There are a lot of firms that have acquired positions, a lot of them with 100% equities, and we are actively looking at building up the exploration portfolio to give us opportunities where drilling will occur earlier than the competitive exploration blocks that we won in Round 3.”

TotalFinaElf is also on the lookout for farm-in opportunities and says its upstream expertise could be useful in joint ventures with Petrobras. “We are very interested in working with Petrobras on fields that may be difficult [to explore or develop] … and of which we have good knowledge,” says Patricia Arditty, TotalFinaElf’s vice-president for E&P in the southern cone of South America.

She says the company’s experience of deep-water projects offshore west Africa, and its knowledge of heavy-oil resources and of high-pressure, high-temperature fields could make it a valuable partner. “We hope that if Petrobras’ policy is to invite companies to work with it on fields it owns, we will be one of them.”

Outright acquisition is another avenue of potential growth, as Shell has recently demonstrated by purchasing Enterprise (Martin’s comments were made a few days before the announcement).

Shell’s press release stressed the importance of the Brazilian assets it will be buying: “In Brazil, Enterprise’s development operatorship builds on Shell’s existing commitment to this key region and enhances Shell’s holdings in high-potential, deep-water blocks.”

In defence of the bid rounds, Simões argues that not all the most attractive deep-water acreage has been licensed. “Attractiveness is a function of several factors, including data availability, exploration maturity and companies’ strategies. What may be attractive for one company may not interest another company. What may be unattractive at a particular moment may become attractive later in the light of new exploration concepts.” To back up the point, he cites the steady growth of interest in the Brazilian equatorial-margin basins, which were not considered attractive until recently.

This view is shared by José Coutinho Barbosa, Petrobras’ E&P director. Although he acknowledges that the most attractive areas have been licensed, he says competition ensures there is a greater variety of exploration concepts and, therefore, a greater chance of exploration success. “In the past, we thought we were running out of oil, when actually we were running out of ideas.”

Drilling disappointments
But the absence of a big commercial discovery is a fact and the industry is in need of some good news. Mark Katrosh, general manager, Amerada Hess (which operates four blocks and has investments in a further two), says that, with the possible exception of a heavy-oil discovery made by Shell (not yet declared commercial), “none of us has found a headline discovery. We are disappointed we have not established a commercial opportunity, but we still think Brazil has high-impact prospects and we continue to invest.” The company plans to drill one or two wells next year.

TotalFinaElf’s Arditty says: “Most of the international companies that ran to Brazil [after the opening in 1997/98] … were quite disappointed. Very few real discoveries were made.” That said, TotalFinaElf has found oil in its Curio well, in the Campos Basin’s BC-2 block (and, in August, acquired a two-year extension to the exploration period). This month, it will drill a second exploration well in BC-2 (TotalFinaElf, 35% and operator; Petrobras, 35%; Shell, 15%; and Enterprise, 15%). “This will be the real test for the value of the block,” says Arditty.

She adds that despite the disappointing discovery record in general in Brazil so far, TotalFinaElf remains committed to the country’s upstream sector and optimistic about its longer-term prospects. “We are willing to stay in Brazil because we believe there are many things to do and probably things to discover and develop.”

BP has shot 6,000 square km of 3-D and 5,000 km of 2-D seismic. It has drilled two exploration wells in BFZ-2, a 25,000 square km frontier area in the Foz do Amazonas basin, 300 km north of the mouth of the Amazon River. One was a dry hole and the other had shows of hydrocarbons. “We have clear indications that there is some prospectivity in the basin and we are still very much in the middle of an evaluation,” says Anderson. But he admits that, in general, “all of the industry has been disappointed. I think that’s fairly clear. You can see that in the lack of major discovery announcements.” But he adds that the country still has major potential. “It’s a huge area and places such as the Campos, Santos and Foz offer opportunities.”

Well density in many areas remains very low. Explorers have barely scratched the surface. Says Enterprise’s Martin: “There have been very few wells drilled in the ultra-deep water. The [deep-water] area is immense, [but] the number of wells drilled is relatively meaningless. As you go out, they are very few and far between and, in Espírito Santo and deep-water Santos, they’re pretty much non-existent.”

Sebastião do Rego Barros, ANP’s director-general, pointed out at a meeting in Houston at the end of March that “only 9% of our sedimentary basins, on land and in the sea, have been explored up to now. A large portion of the Brazilian territory remains untouched from the perspective of oil and gas exploration.”

Brazil has around 6.4m square km of sedimentary acreage, of which only 5% is licensed for exploration. Says Simões: “We expect that significant reserves can be found in those frontier areas and ANP will be acquiring data in these basins to evaluate better their hydrocarbons potential before licensing them in the future.”

While Campos dominates Brazil’s production, there is healthy competition for exploration opportunities in other blocks, especially Santos, Espírito Santo and Pará-Maranhão, he says.

Early days
Analysts say more time is needed to assess the country’s true potential, but note a growing urgency for success. Sondra Scott, director of Latin America energy at Cambridge Energy Research Associates (Cera), says: “It’s very early in the game and we need at least another two years to have a better assessment of whether this is the hotspot everyone thought it would be.”

Prates says the slow discovery rate has probably partly resulted from delays to exploration programmes (mainly caused by the sluggish process for issuing environment permits). He adds that some announcements of commercial discoveries are likely to occur by August, when relinquishments from the first licensing round are due to take place. If there are none by then, he adds, “that could provoke a climate of disappointment”.

Shell, at least, has something to feel positive about (in addition to its purchase of Enterprise). It has made the most significant discovery since the sector was opened to private investment. Announced late last year, the reserves of the Santos Basin’s BS-4 block are estimated to amount to 300m-500m barrels of heavy oil. Kool says the find (made in water 1,550 metres deep) “has given us quite a lot of encouragement, because it is a very large resource in terms of oil in the ground”.

However, he admits it also presents “a lot of technical and commercial challenges”, because the oil is very low gravity – 14-15ºAPI. “Viable production rates may be achievable. We have crossed one hurdle, but there are many more to cross before we’re ready to take a final investment decision.

“We’re going to need to push the envelope of technology at this point. We’re looking at ways of putting more energy into subsea, multiphase pumping. Then, there is the revenue challenge of lower-grade oil, which suffers a discount in the market.” Nonetheless, he says Shell is “cautiously optimistic” that development will proceed.

The joint venture comprises Shell (40% and operator), Petrobras (40%) and ChevronTexaco (20%).

In addition, to the Shell find, Simões says the number of discoveries under appraisal is a positive sign. “We are very optimistic with the number of discoveries under appraisal: more than 20 oil and gas discoveries. Besides those, almost 180 discoveries were reported to ANP, but their appraisal programmes have not been submitted yet. I believe several of those discoveries will lead to development plans once fully appraised and declared commercial.”

Elephant hunters
Alvaro Teixeira, the executive secretary of the Brazilian Institute of Petroleum and Gas, says onshore areas will provide opportunities for smaller discoveries, but the offshore still presents the potential for more major finds. “I think we might find more elephants offshore Brazil.”

Of course, it is Petrobras – already owner of most of Brazil’s licensed exploration acreage and of all of the nation’s giant producing fields – that has the best statistical chance of finding more elephants. In fact, it might have already found one.

According to Coutinho, the company may have discovered a “huge amount” of heavy oil in the offshore Campos and Santos basins.

Without indicating the possible volumes of reserves involved, he says Petrobras will appraise the reservoirs in the second half of the year and will make an announcement around the end of 2002. Separately, the firm continues to explore for lighter grades and is confident it will achieve positive results as it explores new areas, he says.

Simões stresses that it is not a foregone conclusion that Brazil does not have significant reserves of lighter oil. “It is true heavy oil has been found frequently, but light oil, gas and condensate have also been reported. When these reported discoveries are evaluated, we will have a better appraisal of the quality of the oil found.”

But the tendency seems to be tilting towards heavier grades, which, as Kool points out, complicates the economics of production. Oil from Marlim, the country’s biggest producing field, ranges from 17-21ºAPI. Indications from new discoveries (those made by Petrobras and Shell) are of heavy oil. Because discoveries are mostly in deep (400-1,000 metres) or ultra-deep water (over 1,000 metres), finding and production costs are high.

The quality of the oil presents further, expensive technical challenges, such as achieving suitable flow assurance. Finally, the oil produced, because of its poor quality, trades at a large discount to better grades. In addition, Brazil lacks the refining capacity to handle large quantities of heavy grades, meaning producers would theoretically incur additional transportation costs to ship crude to properly equipped refineries overseas, further eroding margins.

Cera’s Scott says the discounts for quality and transportation (assuming there is insufficient local refining capacity) are among the most import challenges facing the industry in making heavy-oil discoveries commercial. “It’s tough to make your economics work if you’re talking about a price that is something like $6-8 [a barrel] underneath [US benchmark grade] WTI.” Ideally, she adds, the solution would be to refine the crude locally and supply products locally, where there is excess demand.

Petrobras’ 53,000 b/d Capuava refinery, Brazil
© Petrobras, Stéferson Faria

Refining investment
Petrobras, which controls 98% of the country’s installed refining capacity, is investing about $1bn a year from 2001 to 2005 on refining. Rogerio Manso, director of Petrobras’ downstream division, says the company’s priority is to adapt its refineries to process increasing volumes of domestic crude. “Most crude has been discovered after the refineries were established – they were designed for lighter and less acidic crudes. We have been investing for the last decade, but we are increasing the thrust of that investment.”

But Petrobras, which operates a de facto monopoly in refining, does not want to retain practically sole responsibility for refining in Brazil and is looking to share the financial burden with other companies.

Last year, Repsol YPF took a 30% stake in the 180,000 barrels a day (b/d) Refap refinery, in southern Brazil, as part of its asset-swap with Petrobras. The Brazilian state-controlled company is looking to enter similar joint-venture deals.

The refining market may also grow as a result of investments by private-sector firms in grassroots plants, or by expansions of existing plants owned by private-sector companies. Local firm Ipiranga is studying a capacity expansion at its own units as well as joint ventures with Petrobras, says its operations director, J Luiz Orlandi.

According to Teixeira: “If we want to be self-sufficient in refining, we have to build two more refineries of 200,000 b/d [each] in five years.”

But Gros clearly lays out Petrobras’ strategy: “In refining, we control 98% of the market, so I’d like to see private capital coming in and taking up the slack. I don’t want to see Petrobras growing in that market.”

Manso adds that, following the Refap joint-venture deal, Petrobras is turning its sights on Reduc, a 240,000 b/d plant to the east of Rio de Janeiro, and has already approached up to 10 suitable partners, but with no success. “We didn’t get the level of interest we expected, so we’re reviewing the proposed model to see if we can make it more interesting to attract a partner to this investment.”

Clearly, part of the problem is that refining is not one of the energy industry’s most profitable areas. BP’s Anderson, for example, says: “BP has recently completed the sale of refinery assets in North America. Never say never, but it’s not been an area of focus for us.”

A matter of timing
However, Scott predicts that large discoveries will catalyse investments in refining. “The minute people start finding heavy crude and producing it there’s going to be a big incentive [to invest in refining]. It’s just a matter of timing.”

Noting the failure of joint-venture negotiations so far, she says: “Once there is pressure to make these deals and place the crude, there may be more willingness to negotiate something more amenable to Petrobras. I guess that what’s been negotiated so far has not been attractive to Petrobras. People are willing to come in, but it’s not the best business in the world, so they’re not willing to do it at a premium.”

Among the closest to becoming a producer is Shell (especially if it goes ahead with its proposed acquisition of Enterprise, which expects its flagship Campos Basin Bijupirá-Salema project to be producing at peak capacity of 70,000 b/d by the end of the year).

Bijupirá-Salema’s oil varies in quality – 28-31ºAPI. But if Shell were to develop BS-4, it would be dealing with 14-15ºAPI crude.

Aldo Castelli, chief executive of Shell Brasil, says the company is “interested [in refinery investments] at the right price”, but that “we need to wait for the right moment”. He adds that uncertainty over the effects of the recent downstream market liberalisation measures, caution ahead of the general election later this year and the task of agreeing a mutually acceptable price with Petrobras are the main barriers to privately owned companies taking some of the pressure off Petrobras in refining.

Prates, who is not optimistic that refinery investments by private-sector companies will be made spontaneously, says state or federal assistance may be needed to provide the initial stimulus. “There should be some incentive on the government side.

There would be no way other than having some help in terms of tax, fiscal incentives or direct money.”

Such plans exist (although they may be put on hold until after the general election). For example, Rio de Janeiro state has been considering investing some of its upstream royalties in downstream expansion. Because value-added tax is levied at the refinery gate, the more products that can be refined locally, the greater state revenue will be in the longer term (revenue that would otherwise fall to other state governments with more refining capacity, such as São Paulo).

Obstacles to investment
In terms of the country’s operating framework, there are several changes E&P firms would like to see. Environmental permitting has been too slow (although this is generally felt to be improving) and there are aspects of the tax system that most participants feel should be tweaked.

But companies do not tend to regard these as the biggest obstacles to investment and are, in any case, generally confident in the capacity of ANP and the government to react to industry needs.

Neither is the risk of investing in Brazil such a sticking point any more. Politically, it is regarded as stable. And although there are major regulatory problems to sort out in, say, the gas-power chain, there is a healthy and growing appetite for project finance in the region (especially compared with Argentina, Venezuela and Colombia).

As one E&P executive puts it: “The main problem is finding oil.”

Rio oil congress to include environmental lobby groups
THE ORGANISERS of the next World Petroleum Congress (WPC) intend to break with tradition by inviting non-governmental organisations (NGOs), such as environmental lobby groups, to participate in the event.

The 17th WPC conference, to be held in Rio de Janeiro, in September, will have two central themes – excellence in technology and responsibility in serving society, with an award for the best exponent of each.

Social responsibility will be taken seriously as a topic, says the executive director of the WPC’s organising committee, Milton Costa Filho. “For the first time, we are very clearly articulating the words responsibility and society – the responsibility of companies not only to their business, but also to society as a whole.”

The event will set an example, he says, by creating employment in local communities and by inviting NGOs to take part. “We will give NGOs space to exhibit their products and ideas – what they are fighting for,” says Costa Filho. “The oil industry is at the forefront of developing concepts of how to work in a socially responsible way and is setting an important example to other industries.”

Francisco Gros, chief executive of Petrobras, says: “Companies in our business have to consider the interests of all stakeholders. We have to worry about the impact of our activities on all of those around us and, in particular, on the communities in which we operate, given the highly polluting nature of our product.”

The congress will be split into four thematic blocks: oil and gas exploration and production; refining and petrochemicals; natural gas; and business management (with economic, environmental and social dimensions). It will be global in scope, but will also allow Brazil to publicise investment opportunities at a time when the energy market reforms of the last few years are beginning to sink in.

Says Gros: “It is very timely that the conference is being held in Brazil. This new possibility of competition is opening extraordinary investment opportunities for companies that traditionally didn’t think of Brazil in view of our monopoly environment.”

Petrobras’ upstream monopoly was formally removed in 1997. Since 1998, there has been a growing number of new participants in exploration. There are 38 exploration and production firms working in Brazil’s upstream sector and that will almost certainly increase in the forthcoming licensing round. Although almost all production is still accounted for by Petrobras, discoveries are starting to filter through.

In addition, the UK’s Enterprise Oil is preparing to start producing at its Bijupirá-Salema field, in the Campos Basin, which will make it the country’s second-largest producer – albeit a long way behind the first. Bijupirá-Salema’s peak rate will be 70,000 barrels a day (b/d), less than 5% of Petrobras’ output of around 1.5m b/d.

The refining market, also dominated by Petrobras, is becoming much more dynamic as well. Refinery gate prices were liberalised at the start of the year and products imports permitted for the first time (total liberalisation was not possible, as Petrobras retains a de facto monopoly in refining. Prices were, in fact, de-subsidised and are now set according to an international benchmark rather than directly by the government).

So far, imports have been negligible, as firms take time to acclimatise to the new system and because Petrobras’ local pricing has been competitive. But over the longer term, competition is expected to grow.

In distribution, competition is healthy and, in retail, it is intense. In refining, Petrobras has a virtual monopoly (with installed capacity of 1.953m b/d, it controls about 98% of Brazil’s total). But it is looking for more joint-venture partners, following the asset swap with Repsol YPF that gave the Spanish company a 30% share of the Refap refinery (and a foothold in the retail market with 234 gasoline stations, among other assets).

With local demand soaring, natural gas is another sector with enormous growth potential.

Alvaro Teixeira, executive secretary, Brazilian Institute of Petroleum and Gas, says: “WPC is focused on the international industry, not on Brazil. But of course it will be a window on Brazil. We lead in the development of deep-water technology, we have many investment opportunities and we have a huge market to be developed in products and natural gas.”

Reflecting the global scope of the congress and Brazil’s prominent position within it, a Fifa-approved charity football match between the world champions and Brazil is set to be held during the congress. If Brazil wins the World Cup, it will play a rest-of-the-world all-star side.

Gas offers major growth prospects
GAS OFFERS vast commercial opportunities in Brazil. There is large, untapped demand for supplies to homes and industrial consumers and, most importantly, an urgent need to increase gas-fired power generation capacity.

The country is dangerously reliant on hydro-electricity for its power needs, which exposes it to power shortages during periods of low rainfall (emergency electricity rationing ended earlier this year after reservoirs dropped to dangerous levels a year ago). Reservoir levels have recovered, thanks to heavy rains in recent months, but the country must diversify its sources of power generation to avoid a repeat.

According to Antonio Luiz Silva de Menezes, director of Petrobras’ gas and energy division, gas accounts for only 3.8% of the energy matrix. But this will rise to about 10% in 2005 and to 12% in 2010.

Gas-fired generating capacity will account for about half of gas demand growth in the next few years. The government plans to have 20% of power generated by gas-fired plants by 2010 (compared with 5% now). Additional gas demand will come from domestic and industrial consumers.

Establishing a suitable framework for investment is the main challenge. As Alvaro Teixeira, executive secretary of the Brazilian Institute of Petroleum and Gas, points out, Brazil is surrounded by enormous reserves (as well as its own resources, huge supplies could come from Bolivia, Argentina, and Trinidad and Tobago). Yet its gas market remains embryonic. “We are on the verge of economic take-off,” says Teixeira. “We are going to need oil, gas and electricity.”

Despite the abundance of gas, upstream success (especially in Bolivia) is yet to translate into downstream revenues. Conversely, the absence of a market structure for gas has, in the past, reduced gas-oriented exploration within Brazil.

“We were in a vicious circle,” says Teixeira. “We didn’t have [domestic] gas, so we didn’t develop a gas market. As we didn’t have a gas market, we didn’t look for gas supplies.” Construction of the Bolivia-Brazil pipeline broke that circle, preparing the gas sector for a phase of sharp growth.

Many problems remain, however. One of the barriers to investment in expensive power stations is that selling cheap electricity in reals is not viable when gas from Bolivia is purchased in dollars.

Francisco Gros, Petrobras’ chief executive officer, says: “Paying for the development of a whole new industry, while at the same time being competitive in the market is the big challenge. But obviously it has to be met and I’m sure it will be met.”

Jean-Paul Prates, executive director of Expetro, a Brazilian oil and gas consultancy, says: “Gas investments are normally dollarised and the price of electricity cannot be dollarised. This is a dilemma that the government has to solve in the middle of the chain, otherwise there will not be upstream and midstream investments in gas and there might be shortages of gas and electricity again.”

Another difficulty is how thermal plants can ensure financial viability in a wet year when the country’s cheaper, hydro-electric plants are utilised at full capacity.

Petrobras expects most of the gas to be imported. “Most of the gas we’ve found is associated gas, so I’d say the growth of the gas business is likely to come from imports,” says Gros. However, Prates and Sondra Scott, director of Latin America energy at Cambridge Energy Research Associates, claim domestically produced gas could play a growing role, which would help iron out the currency problem in the gas-power chain.

Although the country’s many supply options should theoretically drive gas prices down, the prospect of competitive pricing depends, in practice, on how much of the gas-power chain stays under Petrobras’ control. In addition to its majority share in the Bolivia-Brazil pipeline, its large gas reserves in Bolivia and its control of Brazil’s gas trunklines, it has gas supply contracts and will have an expanding equity position in the demand if and when thermal power plants come on line.

A positive factor In terms of the need to diversify power sources is that Petrobras has a major incentive to build generating capacity in Brazil – the need to commercialise big upstream and midstream investments in Bolivia (although, ironically, it may have a disincentive to develop local natural gas resources that might compete with its Bolivian gas).

Headline: Bolivia: innovative solutions
Source: Petroleum Economist
Date: May 2002
Author: Tom Nicholls

FRONT-END engineering and design work for Pacific LNG (liquefied natural gas) could begin at the end of the year, with project sanction following in 2003, says BG, a member of the consortium.

Formed last year, the Pacific LNG group is proposing to pipe gas from Bolivia’s Margarita field to a liquefaction plant on the Pacific coast, probably in Chile. LNG would be exported to a regasification terminal in Mexico, from where gas could be piped into the US network.

The innovative project is drawing interest from other companies, including Petrobras, which operates two large Bolivian gasfields.

In recent years, exploration has vastly increased Bolivia’s gas reserves. But producers now face the daunting task of commercialising them. At the end of 2001, according to government estimates, proved plus probable reserves amounted to 46.83 trillion cubic feet (cf), while proved plus probable, plus possible reserves totalled 70.01 trillion cf (more than seven times the 1998 total).

With domestic requirements limited, the obvious market for Bolivian gas is Brazil, which has huge latent demand and is linked to Bolivia by pipeline. But disputes over access to the Bolivia-Brazil pipeline in the short and medium terms, capacity limitations in the longer term and regulatory obstacles to the establishment of gas-fired power plants in Brazil have forced companies to examine alternatives.

The likeliest development is the expansion of the existing pipeline.

Another solution is LNG. The Pacific LNG partners – Repsol YPF (37.5%), BG (37.5%) and Pan American Energy (25%) – are negotiating a supply deal with Sempra Energy and CMS Energy, which are building the regasification terminal.

“Technical evaluations and commercial negotiations are continuing throughout 2002 to further assess the economics of the project,” says Rick Waddell, BG’s executive vice-president for the southern cone. “This phase of work builds on that undertaken in 2001, and will ultimately confirm project selection and detailed project definition.”

Petrobras, which operates the San Alberto and San Antonio gasfields, has been watching developments with interest. Jorge Camargo, director of Petrobras’ international division, says that while its Bolivian gas will go mainly to thermo-electric plants in Brazil, “we are also monitoring any other initiative to access new markets”. He says Pacific LNG is “a very interesting project”, adding: “We do not rule out the possibility of being involved in the future and, of course, if that’s a project that goes ahead, I think that will interest Petrobras.”

Relations between BG and Petrobras have not been easy in recent years. Last year, the Brazilian energy regulator, ANP, forced TBG (controlled by Petrobras), which has priority access to the Bolivia-Brazil pipeline, to grant firm access to third parties until the end of 2002, allowing them to use idle capacity. BG, which supplies gas to its majority-owned São Paulo distributor, Comgas, and is looking to supply other customers, says it is “working to extend those arrangements”. The company says it will “consider expanding its delivery capacity from the Bolivia-Brazil pipeline, in the light of increased demand from Brazil”.

Waddell says: “We are also looking forward to the open season for capacity in the Bolivia-Brazil pipeline [to be conducted in the second half of 2002 by ANP], but further developments will clearly depend on how the power generation market progresses in Brazil. That, in turn, will depend on the likely level of foreign direct investment and the prospects of export-led growth in the Brazilian economy.”

BG Bolivia has over 4 trillion cf of gas reserves. It is not exploring at the moment, as it is “looking to monetise these further before building up” its reserves base.

Headline: US: mountains of gas
Source: Petroleum Economist
Date: May 2002
Author: Derek Brower

Exploration in the US Rocky Mountains has been going on for decades. But never before has the region seemed so promising for the companies with the expertise to exploit its vast resource of natural gas – potentially the greatest in the US. The only problem is access, writes Derek Brower

WHILE THE US continues to be targeted by foreign natural gas exporters as a market, its cheapest and potentially greatest supply could come from within the country – in basins found in the Rocky Mountains. The area has emerged as the US’ most prolific gas province, attracting producers from across the industry.

“The Rockies are the place to be”, says Jeff Jeggers, a vice-president of exploration and production at Williams Energy. His sentiment is shared by a host of other operators in the region, Anadarko, Devon Energy and Burlington Resources among them.

The majors have also targeted the region. Shell tried to gain a foothold in the mountains last year, but its hostile bid for Barrett Resources lost to a rival offer from Williams.

The reason companies are competing for acreage in the area is the size of the gas reserves. The latest estimates by Colorado School of Mines’ Potential Gas Committee puts conventional reserves at 41 trillion cubic feet (cf), with an additional 14.5 trillion cf of unconventional gas. This makes the Rockies the US’ most prospective gas region, with probable reserves greater than those found in the Gulf of Mexico (GoM), 11 trillion cf, Gulf Coast, 32 trillion cf, Mid-continent, 37 trillion cf, or Alaska, 33 trillion cf.

The Energy Information Administration (EIA) says the region accounts for 35% (of 293 trillion cf) of remaining unproved recoverable reserves in the lower 48 onshore.

Most of the gas (81%) is in unconventional reserves, in several different basins. The San Juan basin, in New Mexico and Colorado – historically the most productive coal-bed methane (CBM) basin – holds about two-thirds of the region’s proved reserves and 80% of its production, says the EIA. The Powder River basin, of Wyoming and Montana, holds recoverable CBM reserves of over 14 trillion cf, according to the US’ Geological Survey. Its estimated reserves were just over 1 trillion cf in 1995.

Much of the recent boom in exploration in the area has been concentrated on the Powder River basin. Last year, there were more than 6,000 producing wells in the basin, compared with 515 in 1998, says the EIA. Production increased by about 190% between 1998 and 2001. The EIA estimates that some 50,000 wells will be needed to tap the resource fully, which could yield more than 5bn cf/d.

The biggest basin is Green River, in Wyoming and Colorado, where the EIA estimates reserves of 160 trillion cf, mainly in tight sands. Other basins include the 430bn cf (CBM) Wind River basin and the 2.3 trillion cf (CBM) Piceance basin.

Table 1: Marketed gas output: Rocky Mountain states

It is not only the abundance of the gas that makes the Rockies so attractive, says Pete Stark, vice-president of industry relations at IHS Energy. The reserves are also cheaper to exploit and more resistant to market fluctuations than other gas sources in the US. Reserves in western Canada are “seeing real depreciation”, with an average decline in well productivity during the past decade. The GoM has similarly failed to live up to expectations.

“Even record levels of drilling [in the GoM] during 2001 only added 108bn cf to production.”

The Mid-continent’s promise has also waned, says Stark. “Most [Mid-continent] gas is found below 15,000 feet. A low percentage of wells are finding sufficient reserves to be successful at $3.00 [/Btu] gas.

“We end up coming back to the Rockies, almost by default,” says Stark. “We need to rely on less-risky Rocky Mountain CBM and basin-centred gas. The GoM and western Canada cannot meet future gas demand by drilling more wells.” New areas such as the Rockies offer the best chance to grow gas production in the near future, he adds, particularly as prices below $3.50/Btu make liquefied natural gas and Arctic gas unfeasible.

The ability to exploit the reserves cheaply is key to the involvement of the companies operating in the Rockies. “Our business here is resilient to market changes,” says Jeggers. Williams is able to ship gas from the Piceance and Powder River basins at a price as low as $1.00/Btu. “We’ve maintained high activity through the recent downturn [in Henry Hub gas prices].” In 17 years in the Piceance basin, Jeggers says the company has had only one period of inactivity – and that was because the drilling rig was committed to wells in the Green River basin. Williams still has 1,000 locations left to drill in the Piceance.

“Williams has never before assembled the large kind of positions as it has been able to assemble in the Rockies, in terms of investment, production and drilling operations,” he adds. Its land in the Powder River basin, where it has reserves of 29 trillion cf and about 1,000 wells, amounts to 1m acres – a fifth of the total basin.

With such widespread drilling, Jeggers says the company can save money by replicating its drilling patterns. “In the past five or six years, we’ve reduced the number of days we spend on a well by a third to one-half.” The company has also increased “expected ultimate recovery” from the wells by 40-50%.

Such know-how has made companies such as Williams attractive to majors lacking experience in the Rockies but eager to book gas reserves there. “Three or four majors have come in, thrown up their arms and left, because they can’t make money here,” Jeggers says. “You have to be able to drill lots of wells and be very efficient.

Skills learned in west Africa, the GoM, the Middle East aren’t transferable to the Rockies.”

But while attractive acreage remains available for development, almost as much is inaccessible. Of 293 trillion cf of unproved Rocky Mountain gas, 33.6 trillion cf are officially barred from drilling, says the EIA. Another 57.7 trillion cf of the resources are de facto off limits because of environmental restrictions. Of the 202 trillion cf that are accessible, 50.8 trillion cf are in land where federal lease stipulations increase development costs by an estimated 6% and add two years to development. Only 151.2 trillion are accessible and commercially feasible.

Assuming the government “increased flexibility” in access and permitting to the areas currently out of reach, the EIA says 28.8 trillion cf could be made available. With the removal of federal lease stipulations, a further 50.8 trillion cf could be added.

Naturally, companies have put pressure on Washington. “Not having access to the best remaining energy prospects hurts the oil and gas industry,” Anadarko says about “access issues” in the Rockies. “But more importantly, it hurts consumers … shrinking supply and ultimately causing higher prices.”

The Independent Petroleum Association of America says that since 1983, access to mineral reserves has decreased by more than 65% – 17% of the total mineral estate is leased today, compared with 72% in 1983. But despite extensive lobbying the issue remains largely ignored.

Headline: Canada: settled boundary dispute to revive E&P
Source: Petroleum Economist
Date: May 2002
Author: WJ Simpson

A 40-year offshore boundary dispute between Nova Scotia and Newfoundland has been settled, spawning government and industry hopes of new oil and gas discoveries in a region where exploration has been waning, writes WJ Simpson

A GOVERNMENT tribunal decision on the ownership of a disputed offshore area has revived long-dormant exploration programmes for the Laurentian sub-basin. The area covers 23,000 square miles, about 100 miles from the shores of both provinces, at the entrance to the Gulf of St Lawrence.

Initial data gathered by the Geological Survey of Canada (GSC) indicates the sub-basin may hold as much as 800m barrels of oil and 9 trillion cf (cubic feet) of gas, which would make it twice the size of Newfoundland’s Hibernia oilfield and three times the size of Nova Scotia’s Sable gasfield.

The tribunal awarded 68.7% of the disputed area to Newfoundland, 29.1% to Nova Scotia and 2.2% to the French-owned islands of Saint-Pierre and Miquelon. For Newfoundland that represents about 8.6m acres of inactive exploration permits held by Conoco Canada and ExxonMobil Canada.

Initial perceptions suggest Nova Scotia was the heavy loser, although the province’s economic development minister, Gordon Balser, says that of the C$1.5bn ($943m) of exploration permits already awarded by the Canada-Nova Scotia Offshore Petroleum Board, Nova Scotia will sacrifice only C$13m in work commitments.

In addition, he says, Nova Scotia can approve its drilling plans almost immediately, while Newfoundland will need several months to authorise work bids for its domain.

“Would we like to have more of the offshore area? Absolutely,” Balser says. “It’s not what I would have hoped for. But what both provinces have are good prospects for exploration on both sides of the line.”


Oh, happy day Newfoundland’s energy minister, Lloyd Matthews, says the ruling was an “incredibly satisfying” day for his province, as it tries to inject fresh life into its offshore sector, and the petroleum industry in general. He says Newfoundland will go to work on enticing exploration companies to the sub-basin. “All we’ve had so far are educated guesses (on the potential). It will take millions of dollars to find out the real answers.”

Newfoundland, despite a decision in March by Husky Energy and Petro-Canada to proceed with the White Rose oil project, has seen its oil industry start to flounder. It has not had a significant discovery since White Rose, in 1984, and has been struggling to persuade companies to invest up to C$60m in deep-water wells.

Lucia MacIsaac, director of the Centre of Excellence in Petroleum Development at Nova Scotia’s University College of Cape Breton, says the existing Laurentian leaseholders – dominated by Conoco, ExxonMobil, Imperial Oil, Kerr-McGee, BP, EnCana (the new company resulting from the merger of Alberta Energy and PanCanadian Energy) and Anadarko – will be able to evaluate their plays in an atmosphere of regulatory certainty, confident that they will have the opportunity to explore.

But she says that, although Newfoundland has been awarded almost 70% of the area under dispute, the geology will “determine who comes out the winner”. Even if a commercial gas discovery is made on the Newfoundland side, the gas would likely come ashore in Nova Scotia, where the processing plants and pipelines are in place to serve the northeastern US.

A Canadian Association of Petroleum Producers’ spokesman says progress towards regulatory certainty and clarity “will result in increased interest by the oil and gas industry to explore”. He says a number of companies have shown interest in starting programmes once the boundary issue was resolved, but cautioned it could be several years before rigs move into the area.

The first positive hint of action came from Conoco Canada, which inherited three blocks, one of them covering 8.6m acres, when it acquired Gulf Canada Resources last year. “The licences were obtained a long time ago and we have been waiting for a long time to explore them properly,” says the firm’s president, Henry Sykes.

Because the properties are so close to major North American markets, Conoco would be satisfied if it discovered either oil or gas.

Infrastructure is already in place to deliver 560m cf/d from Nova Scotia’s Sable project, with EnCana aiming to bring its Deep Panuke field on stream at 400m cf/d by 2005, while Newfoundland’s Hibernia and Terra Nova oilfields are close to a combined 250,000 barrels a day (b/d).

Sykes says Conoco will start examining development options with its partners, which include ExxonMobil and Imperial.

Of the other major players, Imperial says the boundary ruling was a “first step towards opening the Laurentian sub-basin”, while Kerr-McGee says it needs time to study a decision that has shifted one-third of its exploratory licence to Newfoundland territory before it discusses exploration prospects.

The only attempt at exploration in the sub-basin occurred last year in the French territorial waters, when Gulf Canada’s Bandol-1 well, drilling on an 800,000-acre block, came up dry and was abandoned, with the data being analysed to determine the next steps.

However, with one barrier to exploration being removed, another challenge looms from environmentalists and the fishing industry in Atlantic Canada. A Nova Scotia government-appointed commission says more study is needed on the impact of oil and gas exploration off Cape Breton before drilling can begin near the island at the northwest end of the Laurentian sub-basin.

Environmental concerns
Commissioner Teresa MacNeil, who sifted through 130 submissions, recommended the Nova Scotia and Canadian governments create a working group to asses the “many valid concerns” about the potential environmental damage from offshore activity. Balser says he will discuss the recommendations with the federal government and regulators to determine how to proceed.

It is not clear whether further study would affect an application by Hunt Oil and Corridor Resources to begin exploring in the area, starting with an extensive seismic programme, then drilling a C$15m well offshore Cheticamp, Nova Scotia, in an area geologists estimate contains 500bn cf of gas.

TotalFinaElf also has plans to spend up to C$2m later this year exploring two licensed offshore parcels in the Sydney Bight.

Opposition to exploration has been most intense from the Canadian Council of Professional Fish Harvesters, which says the southern Gulf of St Lawrence deserves the same protection as Georges Bank, off southwest Nova Scotia, where there is a moratorium on exploration until the end of 2012.

The GSC estimates potential reserves on the Canadian side of George’s Bank – which straddles the offshore boundary between Nova Scotia and Maine – at 10 trillion cf of gas and 2bn barrels of liquids. The Canadian side covers about 16,000 square miles or one-sixth of the area.

Headline: The search for new Russian oil
Source: Petroleum Economist
Date: May 2002
Author: Isabel Gorst

With output outstripping discoveries, Russia must increase exploration. Most prospective, under-explored regions present major commercial and technical challenges and it may be some time before developments take off. But Lukoil claims it has opened a new oil province in the north Caspian Sea. And in addition to Yamal and Irkutsk, the Sakha republic could augment the country’s immense gas reserves, writes Isabel Gorst

AFTER A LONG period of decline in the 1990s, following the Soviet Union’s collapse, Russian oil output has begun to recover and, judging by ambitious targets set by the country’s now mainly privately owned corporations, is set to grow rapidly for several years.

Demonstrating that the industry’s comeback was for real, Russia ousted Saudi Arabia from the top slot in the league of world oil producers in March. The difference between those two oil powers is that Saudi Arabia has huge spare capacity waiting to come on line, while Russia is producing at full throttle. In addition, Russia is extracting more oil each year than it discovers.

One habit from Soviet times is that Russia keeps the size of its oil reserves a state secret. Russian oil majors, such as Yukos, insist Western estimates, such as the 49bn barrels of reserves assigned to Russia in BP’s Statistical Review Of World Energy, are far too conservative. But whatever the true figure, Russian crude and condensates production is outpacing discoveries.

Just 293m tonnes of crude and condensates were discovered in Russia in 2001, according to the natural resources ministry, but oil production totalled 348m tonnes. Most of last year’s oil discoveries were in the Khanty Mansiysk and Yamal Nenets areas of western Siberia, which is already a well established oil province, providing the bulk of the country’s oil and gas.

One reason why Russia’s new corporations have neglected exploration, is because they have been too busy boosting reserves by buying assets. Privatisation of the industry is continuing, although at a far slower pace, and still provides larger firms with opportunities to expand at the expense of smaller enterprises. Under the banner of industry consolidation, Yukos has won licences in eastern Siberia’s Krasnoyarsk region, by buying East Siberian Oil, while Tyumen Oil has moved into Orenburg, in southern Russia, through its acquisition of Orenburg Oil.

Russia does have new oil reserves waiting to be found. But almost all the highly prospective, under-explored regions are areas with extremely challenging conditions and they will require huge amounts of investment, and probably advances in technology, before yielding significant volumes.

Slow progress
Russia’s biggest oil company, Lukoil, has been more active than others in exploring new areas, probably because the quality of its Siberian reserves is in decline. It has used strategic purchases, such as that of KomiTek, to expand outside western Siberia into the Timan Pechora Basin of northwestern Russia. In the northern part of Timan Pechora, near the coast of the Barents Sea, Lukoil hopes to link up with foreign oil majors to tackle high-cost projects under production-sharing agreements, but progress in finalising deals has been slow.

Lukoil boasts that it has opened a new oil province in the north Caspian Sea, off Russia’s Astrakhan region. Ten promising oil and gas structures have been identified on the 8,500 square km Severny block, where Lukoil has been exploring since the late 1990s. Oil and gas have been found at the Khvalynskoye and Yuri Korchagin fields and Lukoil estimates reserves on the Severny block are at least 350m tonnes. Finds have been at depths below 4,000 metres and the area is clearly rich in gas as well as oil.

So far, five out of eight exploration wells in the area have been drilled. Lukoil claims that first oil and gas output could flow from the north Caspian in 2005/06. It has started lobbying for tax breaks to help financing of high-cost offshore projects.

Also, Lukoil has teamed up with Gazprom and Yukos to undertake a geological study of a large area in the Caspian Sea near Severny.

But the project is not an investment priority for any of the firms.

Meanwhile, Lukoil is investigating opportunities in neighbouring waters offshore Kazakhstan and hopes to participate in the exploration of the Kurmangazi block. But Kazakhstani tenders for Caspian blocks have been postponed several times. And the future of offshore projects is clouded by the Caspian Sea’s unresolved legal status.

No secret about the gas
THERE IS NO secret about Russia’s natural gas reserves. At 48 trillion cubic metres (cm), they are the biggest in the world and most of them are controlled by the gas monopoly, Gazprom. Unlike Russian oil reserves, natural gas discoveries are at least keeping pace with production.

Some 634bn cm of gas were found in 2001, just over 50bn cm more than was extracted during the year. Two-thirds of new finds were made in the Irkutsk region of eastern Siberia, an area where, so far, production is negligible. Yamal Nenets in western Siberia, Russia’s biggest gas province, also yielded 196bn cm of new reserves.

Development of reserves on and offshore the Yamal peninsula, which stretches north off western Siberia into the frozen Kara Sea, forms the cornerstone of Gazprom’s plan to buoy production at a rate of 530bn cm/y until 2020. Yamal fields could yield 250bn cm/y of gas and 10m-12m tonnes a year of liquids for a sustained period, according to Gazprom.

A development programme submitted to the government for approval in April calls for work to begin at the Bovanenkovskoye and Kharasaveyskoye gas and condensates fields, at the southern end of Yamal. Other deposits identified as highly prospective include the Novoportovskoye and Rostovtsevskoye oil and gas fields, the Kruzenshternovskoye gas condensates fields and the Tambeyskaya group of fields.

Gazprom estimates some $69.7bn will be invested in the area by 2030 including $24.7bn in field developments and a further $39.2bn in new gas pipelines and modernisation of transport networks.

Yamal will be extremely expensive to tackle. The governor of the Yamal Nenets region, Yuri Neelov, says the area will absorb $65bn of investment. It is likely Gazprom will seek partners to help raise investment. Oil firms such as Lukoil and Surgutneftegaz have already said they would be interested in participating in Yamal projects. But development is unlikely to begin until gas industry reforms are advanced. From Gazprom’s point of view, the most important thing is to see higher domestic gas prices. Oil firms want access to gas pipelines on equal terms with the monopoly.

In eastern Siberia, the most important gas find so far has been in Irkutsk region, where some 1.4 trillion cm of reserves lie at the Kovykta gas and condensates field. Rusiya Petroleum is appraising Kovykta and plans eventually to develop the field as a source of gas exports to China. Shareholders in Rusiya include BP, Tyumen Oil and the Interros Group. Kovykta could eventually form a hub for a number of oil and gas developments in Irkutsk region and the even more remote Sakha republic, which is said to have huge gas potential.