Deep Water Oil The Final FrontierCommodities / Crude Oil Jun 24, 2010 - 01:58 PM GMT
BP's disaster in the Gulf of Mexico, leading to accusation by Obama himself of corporate recklessness, and to huge numbers of lawsuits for damages and loss of earnings, is also capable of leaving very long-term ecological damage. This disaster however underlines the basic problem facing all the major Western oil corporations, and most national oil companies - outside the OPEC states, Russia and a few other oil producer countries with large or relatively low cost, onshore and shallow offshore oil reserves and an export surplus.
The five-largest international oil corporations (IOCs) - shrunken from their previous Seven Sisters number and status - produce less and less oil and face ever-rising exploration and production (E&P) costs to find more oil, and cover their annual capacity loss from geological depletion. The five remaining majors, ExxonMobil, Royal Dutch Shell, BP, Total and Chevron now control less than 10% of remaining world oil reserves, and less than 15% of current total production capacity - in addition they have to give high returns on capital to their institutional and private shareholders.
This requirement is often much weaker for the national oil companies (NOCs): of the top 20 oil and gas producers worldwide, 14 are now NOCs or newly privatized national oil companies, according to Petroleum Intelligence Weekly. The most important are: Saudi Aramco, Gazprom, Iran's NIOC, Mexico's Pemex, Algeria's Sonatrach, PetroChina, Kuwait's KPC, India's ONGC, Brazil's Petrobras, Malaysia's Petronas, Russia's Yukos and Lukoil, and PDVSA of Venezuela. Within this group of NOCs, Saudi Aramco, PDVSA, NIOC, Pemex and PetroChina are now equal rank with the Western IOCs, either in terms of oil production capacity or refining, shipping and other transport capacities, or all three.
The role and strategy of the NOCs in the big importer nations - notably China, and increasingly India - is not only return on capital and shareholder performance, but basic supply of oil and gas for national needs. To be sure, profit and loss are important, but oil resource supply commands the prime role, for NOCs of the major oil importer nations outside the OECD group. This itself reflects the underlying problem of oil resource scarcity in the face of continuing high demand on a worldwide basis.
Deep offshore oil is an apparent solution for the Western IOCs. Reserves, although very expensive to find and slow to develop, can bolster declining onshore and shallow offshore reserves and production capacity. Potential deep water oil resources, usually exaggerated and only a low fraction of which (generally 5%-15%) can be recovered and extracted, may be more than 70 billion barrels, worldwide. Developing this "last frontier" resource, and accelerating development and production of shale gas reserves, is the stated strategy of several IOCs, which like BP have identified deep water oil as their new frontier - in fact their Last Frontier.
In a context dictated by declining oil resources, and lack of easy access to the large national resources of Russia and most OPEC states, except Iraq, the deep water strategy however carries high costs and huge risks. In the case of BP and since the April 20 disaster, its share price has wilted, wiping about $ 60 billion off the corporation's market capitalization in the two months to June 20. BP's need to find about $ 50 billion to cover its likely total exposure to damage and loss payments will almost surely delay the timing of new oil and gas projects or possibly eliminate them. Sequels of this corporate, and ecological disaster are rippling across the oil industry, with concern that additional monitoring and maintenance of deep water projects, and other high risk and high cost operations could hurt earnings, cash flow and return on capital.
Amid the swath of information, the simple questions and answers are however avoided. Why are the oil major corporations including BP, Exxon Mobil, Shell, Total and major NOCs like Petrobras of Brazil and Petronas of Malaysia investing huge amounts to explore and develop deep offshore oil ? As the BP disaster has shown, amounts spent are very high. E&P costs for Petrobras in the extreme depth Tupi field, for example, can be gauged by the $ 220 million price tag for the initial exploratory well and related seismic data collection. To be sure, only oil prices in the range of $ 50 - $ 80 a barrel, and above can make such projects feasible.
The answer is simple: both international and national oil corporations, outside a few very special cases including some OPEC states and perhaps Russia are faced with diminishing and depleting onshore and shallow offshore oil reserves and resources. This is the basic trigger for the rush to The Last Frontier. This frontier focuses water depths now extending to 3.5 kilometres. If onshore and shallow water resources and producible reserves were more abundant, the rush to develop deep water oil would be low or zero.
THE DEMAND DRIVER
The reason that oil has to found is also simple: world demand is recovering, after a short pause in 2008-2009. World demand contracted only about 3.5% year-on-year, during the downturn described by the IMF as the worst global economic recession and financial crisis since 1929. World demand continues to be forecast as growing at an average of about 2% a year, up to 1.75 Mbd extra demand each year, outside recession downturns. Forecasts by the US EIA and the OECD's IEA continue to suggest world demand could attain 115 million barrels a day (Mbd) by 2030, rising from current demand of around 86 Mbd. This will require not only the addition of 29 Mbd of new capacity, over 3 times current total export surplus of Saudi Arabia but also the replacement of capacity losses due to oil resource depletion of around 2.5 - 3.5 Mbd each year. Due to increasing depletion losses in large established onshore and shallow water fields, mostly dating from and found in the 1955-1965 period, the annual replacement requirement will surely climb in the 2010-2020 short term.
Total capacity needed, for new supply to meet increasing demand, and replacement of existing supply lost through depletion, can easily attain 90 Mbd through 2010-2030. This is more than current world total capacity of about 88 Mbd including 2 Mbd underutilized and spare capacity. Likely costs of this can be evoked by taking recent E&P (exploration and production) spending by world private oil corporations. This is around $ 400 - $ 450 billion a year, including natural gas E&P spending. On average this has delivered incremental capacity of about 1 - 2 Mbd a year, and up to 3 - 3.5 Mbd a year of slowed or postponed capacity loss through depletion.
Oil and gas E&P spending has grown radically with oil prices in the last 10 years: from about $ 200 bn a year in 2000, to about $ 450 bn a year in 2009, or a rate of close to 8% a year in nominal US dollar terms, based on IEA data. This agency, we can note, periodically issues what could be called "alarmist" reports on world oil supply, while also forecasting that oil industry E&P spending could attain $ 1000 bn a year by 2016, and that total oil production capacity is able to climb to about 115 Mbd by 2030. The oil price needed for this is also indicated by the IEA, at or above $ 125 a barrel.
WASTE IT, FASTER
Estimates by scientists at the Woods Hole Oceanographic Institute of daily oil discharge into the Gulf indicate as much as 7 - 8 million litres (up to 45 000 barrels/day) is spewing from BP's ruptured seafloor wellhead, of which variable and unsure estimates and claims from BP suggest that up to 15 000 barrels/day is being skimmed and captured, some days at least. Some other estimates suggest that 60 000 barrels/day is being lost. This feat of waste and pollution could potentially continue until September before final remedy, when costly and slow relief well drilling in water depths of 1.5 kilometres followed by cementing, is achieved.
Until April 20, announcementss of big finds in deep water were highly prized by the IOCs and many leading NOCs. According to BP, whose word is now more than somewhat tarnished, its 62% ownership of the Gulf of Mexico Tiber field, in the same Mississippi Canyon seafloor formation as the Macondo field in which 'Deepwater Horizon' was drilling, places BP as N°1 for deep offshore US oil reserves. In turn, deep water oil reserves were, and probably still are considered by Obama's administration as synonymous with US "national energy security". Deep water exploratory drilling was until now strongly encouraged in the US and other major oil importer countries and can likely bounce back if the current BP crisis winds down with an apparent final technological solution, and to be sure, generous damage payments by BP and its partners, notably Anadarko and Transoceanic plc, and their insurers.
This changes nothing relating to the slim resource basis, low recovery rates of oil in place, very high development costs, large amounts of waste, and extreme environment risks. Never mentioned in upbeat, or even euphoric announcement of big new finds in deep water, these reserves at best can be recovered at around 5% - 15% of the oil in place. Reserve finds announced as 1 billion barrels will deliver 50 to 150 million barrels over a timespan able to exceed 10 years. in other words, over 10 years, the so-called "giant discovery" will yield a volume equal to 15 hours - 45 hours of current world oil demand. In many, even most cases the associated gas extracted with the oil is simply flared: World Bank estimates place the loss of associated gas, by flaring in shallow and deep water offshore production at around 150 billion cubic metres a year.
As we know, on a volume-for-volume basis CH4 or methane gas has about a 20-fold more powerful global warming impact than CO2 or carbon dioxide, released in part by burning fossil fuels. When the great cause of reducing global warming is taken seriously, as leaders of major oil importing countries like to claim they espouse, the massive waste of associated gas in deep water oil production should be given major attention.
Worse for the environment, and well hidden within in-company technology audit data, as much as 2% - 5% of the "nameplate capacity" of the producer wells will be lost at the seafloor and in the complex high-tech oil loading and transfer operations. Wells with a "nameplate capacity" of 60 000 barrels a day can attain waste and loss rates of 1200 - 3000 barrels a day. Inside the deep water oil industry, these loss ans waste rates are commonplace, but rarely disclosed or admitted.
INVESTOR SUPPORT TO DEEP WATER OIL
Field discovery announcements are obligatorily large: the bigger the field claimed, the more media and public opinion support, and more government approval. BP claims its Tiber field could hold more than 5 billion barrels, other estimates placing the total closer to 3 bn barrels, but when we use median-case (neither optimist nor pessimist) scenarios for extraction, of around 5% of this oil being extractible, the likely total production form the "hyper massive" Tiber field will be around 200 - 250 million barrels over 10 years or more. An extracted volume of 200 mln barrels would cover 2.2 days of world oil demand or about 10 days of US current oil consumption.
Investor and media presentations rarely or never explain the extreme technology and industrial challenges faced in these environments. Immense challenges are set by the race to find, and develop deep water oil fields. In the Tiber case, drilling is needed to depths more than Mount Everest is high, that is 10 kilometres or 35 000 feet. Extracted oil and associated gas (entirely or almost entirely flared, that is thrown away) are at temperatures often above 235°C and at pressures up to several tons per square inch. The risk of blow-outs, fire or explosion, as well as "regular and normal" loss and pollution from operations can be gauged from the above.
These temperatures, ironically speaking, show the potential for geothermal energy development. Operations in over 3 kilometres water depth, with seafloor temperatures around 1.5°C, and surface water temperatures close to 30°C indicate the large potential for ocean thermal energy conversion (OTEC) technology and applications, for these installations after the final depletion of deep water oil reserves or abandonment of this costly, wasteful and dangerous oil production. Capital spending for deep offshore oil attains extremes only exceeded by onshore tarsand oil extraction and synthetic oil production from coal, gas, or biomass. Brazil's deep offshore Tupi field, another field claimed to contain up to, or more than 5 bn barrels is for example estimated by industry analysts including Neftex Petroleum Consultants as requiring as much as $240 billion to develop. Exploration and proving costs can be gauged from the $ 220 million price tag for the first test well in this field.
The estimated massive amounts of spending required may however only yield production at around 2.5 Mbd when peak output is attained, probably after 2015 if development moves ahead. Peak output from this field may in fact be less than this, depending on total number of platforms (and therefore development costs) being deployed.
In extreme deep water, lost oil is injected at very high temperature, with seafloor gas release at high pressure, into waters at a typical temperature of 2°C at 1.5 kilometres water depth. This makes biodegradation almost impossible, or in any case extreme long period, that is decades or centuries rather than years. It is currently unknown what long-term impacts the spreading of very large "oil sheets" at extreme water depths can or might have on oceanic life systems.
In shallow water production, conversely, there is quite rapid biodegradation of lost oil. This was the case in the Gulf of Mexico's previous most disastrous offshore oil accident, the 1979 Ixtoc 1 spill, offshore Mexico, in about 100 metres water depth and at drilling depths of around 3.6 kilometres, releasing a total of about 3.5 million barrels of crude over 35 weeks.
Simply because the BP disaster is both very large and offshore USA, it is exposed to quite intense and relatively impartial media coverage. Increasing news reports on deep water oil rig accidents and damage to the environment, outside the USA, are gradually becoming available. Accidents, sometimes very grave, and large "routine" losses of oil and massive flaring of associated gas are the basic picture: world offshore oil production results in around 75 - 100 billion cubic metres per year of flared and wasted natural gas. Until now, the technological, industrial and environmental risks of oil production in extreme deep water, and its extreme wastefulness of energy resources have been consistently under-reported and under-estimated.
CAN DEEP WATER OIL PREVENT OIL SCARCITY ?
The principal interest in finding and developing extreme depth oil reserves, despite their small size, high rates of loss and waste in production, very high development costs, long lead times and extreme risks to the environment is simple.
World oil reserves are depleting, and access by the oil major companies, like BP, to the world's most abundant remaining onshore and shallow offshore oil reserves - mainly in the OPEC states and Russia - is impossible, difficult or costly. To be sure the "military option" for gaining access to the national resources of OPEC states, through pillage has been applied in the case of Iraq but the fruits of, or booty from this strategy will be quite long to mature.
The oil majors, all of them based in large oil importer and consumer countries, and the national oil corporations of major importer countries in an increasing number of cases, are therefore forced into deep water. This has the sole target to find whatever oil they can, where they can.
Short-term and stopgap reasoning, and attempts at producing more oil wherever possible are rational or at least predictable in this context, that is 'supply side' solutions. Risk is systematically under-estimated, as proven not only by the BP disaster, but also by recurring smaller accidents and constant loss and waste of large volumes of oil, and massive quantities of gas in deep water operations. The real, demand side solution of reducing oil demand in the large consumer countries on a determined, long-term basis is sidelined as the best, most rational response.
Current deep water oil production, worldwide, is very far from able to prevent global depletion impacts on world oil supply from tending to raise prices. Defined as production in water depths below 1000 metres, current output can be estimated at not much above 1.8 million barrels/day (Mbd) or about 2.1% of world total oil production. Yearly additions of deep offshore oil production capacity are unimpressive and small, certainly below 0.33 Mbd a year.
To be sure, enthusiast advocates of deep offshore oil such as BP (at least until end April 2010) regularly claim the reserve size is very big, and that "several hundred billion barrels" could be available, from extreme water depth operations. Extreme optimists on these "last chance" oil reserves and production of course go further than this, adding at lest one zero to their fantasist estimates of deep water oil reserves.
Under all hypotheses and forecasts, large scale development of deep offshore oil resources would require very high, and increasingly extreme capital spending as water depths increase to as much as 3 - 3.5 kilometres. Technological risks would need to be recklessly ignored, as BP has done, and again like BP there would need to be a complete disregard of risks to human life and to the environment. All of these conditions are however now in doubt, following the BP disaster and increased public and political interest in deep offshore oil.
Due to the low recovery rates, extreme high investment costs, and slow "ramp up" of production capacity in deep offshore oil extraction it is very unlikely that deep water oil can seriously prevent or slow the arrival of structural undersupply of oil to world markets. This will be manifested, as in 2008, by radically high oil prices being attained before there is an inevitable economic slump, reducing oil prices.
By Andrew McKillop
Project Director, GSO Consulting Associates
Former chief policy analyst, Division A Policy, DG XVII Energy, European Commission. Andrew McKillop Biographic Highlights
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