Thursday, September 29, 2011

Worldwide Geothermal Energy Usage

Geothermal energy is thermal energy generated and stored in the Earth. Thermal energy is energy that determines the temperature of matter. Earth's geothermal energy originates from the original formation of the planet (20%) and from radioactive decay of minerals (80%). The geothermal gradient, which is the difference in temperature between the core of the planet and its surface, drives a continuous conduction of thermal energy in the form of heat from the core to the surface.

Geothermal Resource Type


Table 11.1 is based on data for 2008 reported by WEC Member Committees for the present Survey, supplemented by information submitted to the World Geothermal Congress 2010. Of the countries utilising their geothermal resource, almost all use it directly but only 24 use it for electricity generation. At end-2008, approximately 10 700 MWe of geothermal electricity generating capacity was installed, producing over 63 000 GWh/yr. Installed capacity for direct heat utilisation amounted to about 50 000 MWt, with an annual output of around 430 000 TJ (equivalent to about 120 000 GWh).

The annual growth in energy output over the past five years has been 3.8% for electricity production and around 10% for direct use (including geothermal heat pumps). Energy produced by ground-source heat pumps alone has increased by 20% per annum over the same period. The low growth rate for electric power generation is primarily due to the low price for natural gas, the main competitor.

The data show that with electric power generation, each major continent has approximately the same percentage share of the installed capacity and energy produced, with the Americas and Asia having over 75% of the total. Whereas, with the direct-use figures, the percentages drop significantly from installed capacity to energy use for the Americas (26.8 to 13.9%) due to the high percentage of geothermal heat pumps with low
capacity factor for these units in the U.S. On the other hand, the percentages increased for the remainder of the world due to a lesser reliance on geothermal heat pumps and the greater number of operating hours per year for these units.

Worldwide growth of installed geothermal direct use


Geothermal Electric Power

Electric power has been produced from geothermal energy in 27 countries; however, Greece, Taiwan and Argentina have shut down their plants due to environmental and economic reasons. The worldwide installed capacity has the following distribution: 27% dry steam, 41% single flash, 20% double flash, 11% binary/combined cycle/hybrid, and 1% backpressure (Bertani, 2010).

Worldwide geothermal energy direct use


Direct Utilisation (including geothermal heat pumps)

The world direct utilisation of geothermal energy is difficult to determine, as there are many diverse uses of the energy and these are sometimes small and located in remote areas. Finding someone or even a group of people in a country who are knowledgeable on all the direct uses is difficult. In addition, even if the use can be determined, the flow rates and temperatures are usually not known or reported, thus the capacity and energy use can only be estimated. This is especially true of geothermal waters used for swimming pools, bathing and balneology.

The total installed capacity, reported at the end of 2009, for the world’s geothermal direct utilisation is 50 583 MWt, almost a two-fold increase over the 2005 data, growing at a compound rate of 12.3% annually. The total annual energy use is 438 071TJ (121 696 GWh), a 60% increase over 2005, growing at a compound rate of 11.0% annually. Compared to ten years ago the capacity increased 12.8%/yr and the use 8.7%/yr. Thus, it appears that the growth rate has increased slightly in recent years, despite the low cost of fossil fuels, economic downturns and other factors. It should, however, be noted that part of the growth from 2000 to the
present is due, in part, to better reporting, and includes some geothermal countries that were missed in previous reports. The capacity factor is an indication of the amount of use during the year (i.e. a factor of 1.00 would indicate the system is used at a maximum the entire year, and 0.5 would indicate using the system for 4 380 equivalent fullload hours per year). The worldwide average for the capacity factor is 0.27, down from 0.31 five years ago and 0.40 ten years ago. This decrease is due to the increased use of geothermal heat pumps that have a worldwide capacity factor of 0.19 in the heating mode.

The growing awareness and popularity of geothermal (ground-source) heat pumps had themost significant impact on the data. The annual energy use for these grew at a compound rate of 19.7% per year compared to five years ago, and 24.9% compared to ten years ago. The installed capacity grew 18.0% and 20.9% respectively. This is due, in part, to the ability of geothermal heat pumps to utilise groundwater or ground-coupled temperatures anywhere in the world.

The countries with the largest installed capacity were the USA, China, Sweden, Norway and Germany, accounting for about 63% of the installed capacity and the five countries with the largest annual energy use were: China, USA, Sweden, Turkey and Japan, accounting for 55% of the world use. Sweden, a new member of the ‘top-five’ obtained its position due to the country’s increased use of geothermal heat pumps. However, if considered in terms of the country’s land area or population, then the smaller countries dominate.

The ‘top-five’ then become Netherlands, Switzerland, Iceland, Norway and Sweden (TJ/area), and Iceland, Norway, Sweden, Denmark and Switzerland (TJ/population). The largest increases in geothermal energy use (TJ/yr) over the past five years are in the United Kingdom, Netherlands, Korea (Republic), Norway and
Iceland; and the largest increases in installed capacity (MWt) are in the United Kingdom, Korea (Republic), Ireland, Spain and Netherlands, due mostly to the increased use of geothermal heat pumps.

Categories of geothermal energy direct usage


In 1985, there were only 11 countries reporting an installed capacity of over 100 MWt. By 1990, this number had increased to 14, by 1995 to 15, by 2000 to 23 and by 2005 to 33. At present there are 36 countries reporting 100 MWt or more. In addition, six new countries, compared to 2005, now report some geothermal direct utilisation. In Fig. 11.10 district heating is estimated at 78% of total space heating energy use and 82% of the installed capacity. Snow melting represents the majority of the cooling/snow melting figure.

Installed geothermal electricity capacity

Wednesday, September 28, 2011

Oil supply from West Africa



With the recent focus on supply disruptions and the potential for continuing unrest in North Africa and the Middle East, several positive developments in oil supply from West Africa may have escaped attention. Arresting earlier declines, the region's top two producers, Nigeria and Angola, have each managed relatively robust production and export performances, helping offset shortfalls in supply from Libya, Syria, and Yemen. Both countries offer the promise of further, significant capacity additions in the short- to medium-term, although, in Nigeria, some major challenges remain. The region also includes a number of emerging suppliers, including Ghana, which has experienced a rapid ramp up in output from less than 10,000 barrels per day (bbl/d) last year to over 90,000 bbl/d by mid-2011.

The importance of West African crude streams to the world oil market reflects their quality as well as their volume. Nigeria's light, sweet (low-sulfur) crude grades, with their high gasoline yields, came in particularly high demand when civil war broke out in Libya earlier this year, as they offered relatively close substitutes for Libyan oil. Ordinarily, according to Lloyd's List Intelligence APEX database, the United States takes the lion's share of Nigeria's crude exports (43 percent in 2010), followed by India (14 percent) and Brazil (8 percent), while China attracts the bulk of Angolan exports. In 2010, the U.S. accounted for only 23 percent of Angolan exports, far behind China (45 percent), with India and Taiwan together accounting for another 15 percent.

Collectively, West Africa remains an important source of U.S. oil supply, accounting for roughly 14 percent of total U.S. oil imports last year, even as increased volumes were being shipped to Asian markets. West Africa was the third largest supply region for U.S. imports in 2010, trailing behind the Persian Gulf and well behind the Americas, including Canada, which is by far our largest source of imports. Nigeria and Angola, the dominant West African suppliers which are both OPEC members, together shipped a combined 1.4 million bbl/d of oil to the United States in 2010, placing them among the top ten sources of U.S. oil imports. Non-OPEC West African producers accounted for another 230,000 bbl/d of U.S. oil imports.
U.S Oil Imports of Africa

Since its 2005 peak, Nigeria's oil production has faced two major problems: politically motivated attacks by local groups seeking a share of the oil wealth and protesting against environmental damage caused by oil companies, and economically-driven oil theft. This "illegal bunkering", a commonly used euphemism for pilfering oil from pipelines, often causes pollution, pipeline damage, and production shut-ins. Annual average production slipped to less than 2.2 million bbl/d in 2008, from 2.6 million bbl/d in 2005 (including crude oil and lease condensate). The U.S. Energy Information Administration (EIA) estimates that direct attacks on Nigeria's oil infrastructure, pipeline leaks, and explosions caused by illegal bunkering have, at times, caused crude production to range between 1.7 million bbl/d to 2.1 million bbl/d, well below the nameplate capacity of about 2.9 million bbl/d.

Under an amnesty reached in August 2009, however, many Niger Delta militants handed over their weapons to the government in exchange for cash payments and training opportunities. This amnesty has led to decreased attacks and some companies have been able to repair damaged oil infrastructure. In April 2011, Goodluck Jonathan, a southerner from an oil state who had risen from Vice-President to President of Nigeria upon the death in office his predecessor, was elected to a full term as President, which may help to soothe discontent and foster a sense of empowerment among disenfranchised communities of the oil-rich Niger Delta. While political violence has not disappeared, its focus appears to have shifted to the northern provinces, leaving oil facilities relatively unscathed.

In 2010, Nigeria's total oil production reached 2.5 million bbl/d, making it the largest oil producer in Africa. Crude oil production averaged about 2.1 million bbl/d for the year. Recent offshore oil developments combined with the restart of some shut-in onshore production have boosted crude production to nearly 2.2 million bbl/d in July 2011. Planned upstream developments could further increase Nigerian oil production in the short- to medium-term. On paper, projects announced by international oil companies (IOCs) could add more than 1.2 million bbl/d to the country's production capacity by 2016, though delays are virtually certain.

While political violence has abated, illegal bunkering and other criminal attacks have persisted, due in part to weak economic development and the lack of progress in job creation. In addition, whether and when planned production startups materialize will depend on the progress of a far-reaching reform of the energy sector, the Petroleum Industry Bill (PIB), first introduced in 2009. While the bill generally aims to boost government revenue by making the Nigerian oil sector more efficient, some of its provisions seek to renegotiate contracts with IOCs and raise taxes and royalties. Although parts of the PIB have recently been made into law, the Bill in its entirety continues to be debated by the National Assembly. This ongoing debate has already caused substantial delays in investments in oil exploration and project development, and has also affected the natural gas sector.

In Angola, several startups look set to significantly raise short-term production. In 2010, Angola produced an estimated 1.9 million bbl/d of crude oil, up from less than 500,000 bbl/d in the early 1990s. In the first half of 2011, however, production decreased to an average of just below 1.7 million bbl/d, due mostly to technical problems in the Saxi-Batuque and Greater Plutonio projects. In the second half of 2011, production is expected to return to earlier peaks as these problems are resolved, adding back about 150,000 bbl/d. Additional increases are expected from the recent startup of the 220,000 bbl/d Pazflor project and the upcoming 150,000 bbl/d PSVM project in early 2012. 

Sharara oil field will begin operating within 2 weeks.

LIBYA’s 400,000 barrel a day (b/d) Sharara oilfield will begin producing and sending crude up a pipeline to the refinery and export terminal in Zawiyah, west of Tripoli, within two weeks, according to facility operators. 


“There is nothing damaged,” Hussain Elhengari, managing director at Akakus Oil company, a joint-venture between Repsol and Libya’s National Oil Company, said of the oilfield. 


Worries over the safety of accommodation for workers at Sharara are preventing an immediate resumption of output, said Elhengari. A spokesman for Repsol, a minority shareholder in the project, said from Madrid that there was “no schedule” for the field. 


But on the ground, operators are confident output is close. Some of Muammar Qadhafi loyalists remain in Ubari, a small town southwest of Sebha, half way between the field and the refinery. But efforts to “clear” the area were underway and it could be safe to return in a week to 10 days, said Elhangri. 


Output from Akakus’s Sharara field accounted for about a quarter of Libya’s pre-war production, and is prized in international markets for its high, 43°API, quality. 


The pipeline and fibre-optic telecommunications cable running from Sharara to Zawiyah was in “perfect” condition, said Elhangri. In July, rebel forces shut a valve on the pipeline and cut the cable in two places – a tactical move that shut down the 120,000 b/d Zawiyah refinery and denied Qadhafi’s forces access to gasoline. Both have been fixed. 


Sharara’s near resumption, though, is just another example of a recovery in Libya’s oil sector that is confounding the predictions of analysts outside Libya. 


Several fields are already back on stream. The biggest is Arabian Gulf Oil’s (Agoco) Sarir field, southeast of Libya, which is now producing 160,000 b/d and is still ramping up. Production form the nearby Misla field, also operated by Agoco, is imminent, too, and could hit 100,000 b/d as its output speeds up in coming weeks. The two fields produced about 400,000 b/d before the war. 


Foreign operators Total and Eni are also back in business. The Italian firm said on 26 September it had brought back on stream 15 wells at the Abu Attifel fields, south of Benghazi, yielding about 32,000 b/d, or just under half of pre-war production. France’s Total is producing from the 40,000 b/d offshore Al Jurf field, too, though it hasn’t reached its capacity yet. 


Even fields that analysts said would be tricky to restart may prove easier than thought. 


The Waha complex, whose shareholders include ConocoPhillips, Marathon and Hess, produced 400,000 b/d from fields in the Sirte basin, in the centre of the country. The age of the fields, said some analysts, would mean production would only come back slowly, and need careful handling – probably by foreign experts. 


Nonsense, said Nasser Aljaly today in an interview with Petroleum Economist. He worked on the fields and is now chairman of Zawiyah Refinery Company (ZRC). The only real obstacle to Waha’s return is access to electricity to power the wells' pumps, he said, and generators would quickly solve that. 


Nor would it take even two years for the country to reach pre-war output, he said, citing the forecasts of pessimistic “analysts outside Libya”. By then, he said, the industry would be bringing on greenfield projects. Reaching 1.6 million b/d, the level before the uprising, would take less than a year, he added. 


None of Libya’s wells had been affected by the war – and damaged surface facilities would be fixed quickly, Aljaly claimed. 


Even though output from Libya is coming back on swiftly – with 500,000 to 1 million b/d now looking possible within months -- little of it is reaching international markets or, yet, earning much income for the fledgling government. mThat’s because until Sharara comes back on stream, Sarir’s output through the pipeline to Tobruk, in Libya’s east, is destined for Zawiyah. 


One 600,000 barrel cargo laden with Sarir crude will arrive at the plant on 29 September, said Khalifa Emhamed Sahli, ZRC’s general manager. On its way the ship will stop at Mellitah, west of Zawiyah, so the crude can be blended with some Mellitah oil to increase its API. 


On 30 September, one of Zawiyah’s two 60,000 b/d processing units will begin refining that crude into gasoline for the local market, easing Libya’s fuel import needs. If necessary, National Oil Company, the parent company of both Agoco and ZRC, will ship a second 600,000 barrel cargo to Zawiyah. 


One or two cargoes, said Sahli, would tide the refinery over until Sharara was on stream. After that, Tobruk’s Sarir and Misla exports will be for foreign markets. 


Even then, though, it won’t be a big earner for the National Transitional Council, because trading firm Vitol will claim cargoes in lieu of payment for shipments of gasoline it sent the rebels’ way during the war. But clearing that bill may take a lot less time than expected. 

Tuesday, September 27, 2011

History of the Oil Shale Industry


The use of oil shale can be traced back to ancient times. By the 17th century, oil shales were being exploited in several countries. One of the interesting oil shales is the Swedish alum shale of Cambrian and Ordovician age that is noted for its alum content and high concentrations of metals including uranium and vanadium. As early as 1637, the alum shales were roasted over wood fires to extract potassium aluminium sulphate, a salt used in tanning leather and for fixing colours in fabrics.

Late in the 1800s, the alum shales were retorted on a small scale for hydrocarbons. Production continued through World War II but ceased in 1966 because of the availability of cheaper supplies of petroleum crude oil. In addition to hydrocarbons, some hundreds of tonnes of uranium and small amounts of vanadium were extracted from the Swedish alum shales in the 1960s.

An oil shale deposit at Autun, France, was exploited commercially as early as 1839. The Scottish oil shale industry began about 1859, the year that Colonel Drake drilled his pioneer well at Titusville, Pennsylvania. As many as 20 beds of oil shale were mined at different times. Mining continued throughout the 1800s and by 1881 oil shale production had reached 1 million tonnes per year. With the exception of the World War II years, between 1 and 4 million tonnes of oil shale were mined each year in Scotland from 1881 until 1955, when production began to decline, before ceasing in 1962. Canada produced some shale oil from deposits in New Brunswick and Ontario in the mid-1800s. 


Oil Shaled mined between 1880 and 2000


Common products made from oil shale from these early operations were kerosine and lamp oil, paraffin wax, fuel oil, lubricating oil and grease, naphtha, illuminating gas, and the fertiliser chemical, ammonium sulphate. With the introduction of the mass production of automobiles and trucks in the early 1900s, the supposed shortage of gasoline encouraged the exploitation of oil shale deposits for transportation fuels. Many companies were formed to develop the oil shale deposits of the Green River Formation in the western United States, especially in Colorado. Oil placer claims were filed by the thousand on public lands. The Mineral Leasing Act of 1920 removed oil shal and certain other fossil fuels and minerals on public lands administered by the Federal Government from the status of locatable to leaseable minerals. Under this Act, the ownership of the public mineral lands is retained by the Federal Government and the mineral, e.g. oil shale, is made available for development by private industry under the terms of a mineral lease.

Several oil shale leases on Federal lands in Colorado and Utah were issued to private companies in the 1970s. Large-scale mine facilities were developed on the properties and experimental underground 'modified in situ' retorting was carried out on one of the lease tracts. However, all work eventually ceased and the leases were relinquished to the Federal Government. Unocal operated the last largescale experimental mining and retorting facility in the western United States from 1980 until its closure in 1991. The company produced 4.5 million barrels of oil from oil shale averaging 34 gallons of shale oil per ton of rock over the life of the project. After many years in the doldrums, interest in oil shale was rekindled in 2004 (see the Country Note on the USA). The tonnages mined in six oil shale producing countries for the period 1880 to 2000 are shown in Fig. 3.2. By the late 1930s, total yearly production of oil shale for these six countries had risen to over 5 million tonnes. Although production fell in the 1940s during World War II, it continued to rise for the next 35 years, peaking in 1979-1980 when in excess of 46 million tonnes of oil shale per year was mined, twothirds of which was in Estonia. Assuming an average shale oil content of 100 l/tonne, 46 million tonnes of oil shale would be equivalent to 4.3 million tonnes of shale oil. Of interest is a secondary period of high production reached by China in 1958-1960 when as much as 24 million tonnes of oil shale per year were mined at Fushun.

The oil shale industry as represented by the six countries in Fig. 3.2 maintained a combined yearly production of oil shale in excess of 30 million tonnes from 1963 to 1992. From the peak year of 1981, yearly production of oil shale steadily declined to a low of about 15 million tonnes in 1999. Most of this decline is due to the gradual downsizing of the Estonian oil shale industry. This decline was not due to diminishing supplies of oil shale but to the fact that oil shale could not compete economically with petroleum.



Related Topic: Untapped Oil Reserves Could Fuel U.S. For 300 Year

Wind Energy Costs




The cost of wind energy plant fell substantially during the period from 1980 to 2004. Prices in the 1980s were around US$ 3 000/kW, or more, and by 1998 they had come down by a factor of three. During that period the size of machines increased significantly - from around 55 kW to 1 MW or more- and manufacturers increased productivity substantially. In 1992, for example, one of the major manufacturers employed over seven people per megawatt of capacity sold, but by 2001 only two people per megawatt were needed. The energy productivity of wind turbines also increased during this period. This was partly due to improved efficiency and availability, but also due to the fact that the larger machines were taller and so intercepted higher wind speeds. A further factor that led to a rapid decline in electricity production costs was the lower operation and maintenance costs.

With capital costs halving between 1985 and the end of the century, and productivity doubling, it could have been expected that electricity production costs would fall by a factor of four. This general trend has been confirmed by data from the Danish Energy Agency; these suggest that generation costs fell from DKK 1.2/kWh in 1982 to around DKK 0.3/kWh in 1998 (Danish Energy Agency, 1999). Shortly after the turn of the century, the downward trend in wind turbine and wind farm prices halted and prices moved upwards. This was partly due to significant increases in commodity prices and partly due to shortages of wind turbines. Prices appear to have peaked in 2008, with complete wind farms averaging just under US$ 2 200/kW and wind turbines at just under US$ 1 600/kW. Prices may now be falling, based on data available to the autumn of 2009.

Generation costs

No single figure can be quoted for the installed cost of wind farms, as much depends on the difficulty of the terrain, transport costs and local labour costs. Generation costs depend, in addition, on the wind speed at the wind farm site - since this determines the energy productivity - and on the financing parameters. The latter depend on national institutional factors which influence whether wind farm investments are seen as high or low risk. Although there is a broad consensus that wind turbines are now sufficiently reliable to enable depreciation over a 20-year period, the 'weighted average cost of capital' (WACC) may lie between 5% and 11%. (The WACC is a weighted average interest rate that takes into account the cost of both bank loans and equity investments).Typical generation costs are shown in Fig. 12.5, using installed costs between US$ 1 700/kW and US$ 2 600/kW, an 8% interest rate and a 20-year amortisation period. 


Operating costs, which cover the costs of servicing, repairs, management charges and land leases have been set at US$ 32/kW/yr for the lower capital cost and US$ 60/kW/yr for the higher capital cost. The link between wind speed and energy productivity has been established by examining the performance characteristics of a number of large wind turbines that are currently available. Although there is not a unique link between wind speed and capacity factor, the spread is quite small. All wind speeds refer to hub height. The estimates suggest that generation costs at US$ 2 600/kW range from just under US$ 200/MWh at 6 m/s, falling to US$ 84/MWh at 9.75 m/s. At US$ 1 700/kW, the corresponding range is US$ 125/MWh to US$ 53/MWh, respectively.


Renewable energy's share of U.S.

Monday, September 26, 2011

Electric power price division between upstate and downstate New York


Source: U.S. Energy Information Administration, based on Federal Energy Regulatory Commission chart.


Electric power often costs more in New York City, Long Island, and the Hudson Valley than in the rest of New York—especially for the mid-afternoon—due to transmission constraints on moving power into the New York City area. The chart above, published by the Federal Energy Regulatory Commission (FERC), shows a typical example of diverging prices for those regions in the day-ahead market, where market participants bid to provide electricity for each hour of the upcoming delivery day. Location-specific prices in the day-ahead market respond to expected conditions like transmission constraints; the real-time market responds to the events of the day, such as unpredictable weather events or generator outages.

Last week, Today in Energy used a series of maps to illustrate location-specific prices in wholesale electricity markets (Locational Marginal Prices—LMPs). Comparing prices in different zones over the same time period, however, requires charts like those produced by the Federal Energy Regulatory Commission—daily charts with a few key LMPs for each of five areas of the country served by regional transmission organizations (RTOs).

Differences among LMPs usually boil down to transmission constraints across an RTO. This article takes the New York Independent System Operator (NYISO) as an example. In New York, there is a persistent transmission constraint between upstate and downstate, limiting the amount of electricity that can flow into New York City and Long Island from the north. This situation commonly results in higher prices in New York City, on Long Island, and often in the Hudson Valley (the northern approach to NYC) as well.

The chart above shows the split between upstate (West, Capitol, and North) and downstate (New York City, Long Island, and Hudson Valley) prices in the mid-afternoon on September 12, 2011. Every weekday, FERC publishes a chart of the previous weekday's LMPs as established in the day-ahead market for several RTOs. (FERC includes charts for weekend days in their archive files.) In the example, day-ahead prices for Monday, 9/12 were posted by FERC on Tuesday, 9/13. The chart includes:
LMPs by zone and by hour, as discussed above, are plotted on the left axis.
Cleared load is plotted on the right axis, also by hour, for the entire NYISO. Demand for electric power changes over the course of the day. NYISO "clears" a certain amount of load in hourly chunks, to be supplied by generators placing winning bids in the day-ahead market. For this fairly mild September day, hourly cleared load topped out around 26,100 megawatts (MW), nowhere near the load record for NYISO of 33,939 MW, set in 2006.

Even on this fairly lightly-loaded day, however, upstate LMPs diverged from downstate LMPs during the morning ramp, with the split increasing as load increased, up through the afternoon peak between 4 and 5 p.m., and then narrowing at the end of the day. For much of the day, wholesale electricity prices were higher in New York City, Long Island, and the Hudson Valley than in the remainder of New York State.

The prices in the chart above apply to the portion of total electric power demand cleared in the day-ahead market. This represents most of New York's electricity supply. For the small additional portion of power required to meet the actual load on a given day, the NYISO also runs a real-time market, which takes and clears bids from generators to supply power on a real-time basis. The 5-minute, real-time prices are averaged over the hour in the chart below, which includes: LMPs, plotted on the left axis in dollars per megawatthour
The actual load observed by NYISO, plotted on the right axis in megawatts
The forecasted load from the previous day in megawatts.


Source: U.S. Energy Information Administration, based on Federal Energy Regulatory Commission chart.

LMPs in the real-time market often behave differently than in the day-ahead market. The real-time market tends to be more volatile, and responds to the events of the day, such as a thunderstorm alert or an unplanned generator outage requiring fast-starting but higher-priced generators to come on line, as seen in PJM on August 23, 2011 when an earthquake hit the East Coast. In the case of the New York chart above, transmission equipment outages upstate in the morning led to higher real-time prices downstate. Because transactions in the real-time market represent only a small portion of total electricity supplied, high real-time prices rarely translate into significant increases in retail power prices. However, sustained high, real-time prices can influence the day-ahead market, as seen in ERCOT during a supply shortage in August 2011.



The charts discussed above are representative of only one report on FERC's website on electric power market oversight; FERC also has a separate website devoted to market oversight for natural gas.

Oil Sanctions on Syria


Syria has recently become the target of tightened international sanctions prohibiting its oil exports to the United States and European Union. While Syria and Libya are both Mediterranean crude oil producers undergoing major political strife, differences in the amount of oil they produce and export, its quality, and the scope of the disruption all suggest that the situation in Syria, in contrast to that in Libya, is unlikely to have a significant direct impact on world oil markets.

Syria's oil output of less than 400,000 barrels per day (bbl/d) in 2011 makes it the only significant oil-producing country in the eastern Mediterranean, but still a relative minnow compared to Libya's pre-unrest total oil production of over 1.7 million bbl/d. Estimated net crude oil exports from Syria were only 109,000 bbl/d in 2010, far less than those from Libya (1.5 million bbl/d in 2010). More than 90% of Syria's oil exports went to countries in the European Union (E.U.), with Germany, Italy, France and the Netherlands as the largest buyers. But while crude exports to the E.U. thus provided 30% of Syrian government revenues in 2010, they made up only about 1% of E.U. petroleum demand, European Commission data show. This contrasts with Italy's approximately 20% dependence on Libyan crude oil imports last year. Unlike Libya's crude, which is light and sweet and for which there are few readily available substitutes, the bulk of Syria's crude oil is relatively heavy and sour.

Various U.S. sanctions against Syria were enacted starting in 2004, including the Syria Accountability Act (SAA) of 2004, which prohibits the export of most goods containing more than 10% U.S.-manufactured component parts to Syria. Other sanctions include measures against the Commercial Bank of Syria resulting from the USA Patriot Act and various Executive Orders denying certain Syrian citizens and entities access to the U.S. financial system due to their participation in proliferation of weapons of mass destruction, association with Al Qaida, the Taliban or Osama bin Laden, or destabilizing activities in Iraq and Lebanon. Until recently, U.S. measures did not specifically target oil exports, though they may have hampered Syrian efforts to arrest a decline in domestic crude production by reducing opportunities for exploration and production partnerships with foreign companies.

In response to the indiscriminate use of deadly force against dissent by Damascus, U.S. sanctions on Syria were extended on August 18 to include a ban on the import of crude oil or petroleum products of Syrian origins. Prior to the new round of U.S. sanctions, the United States infrequently imported crude oil, and only a small amount of refined products, from Syria. More significantly, on September 2, the E.U. followed suit with its own ban on imports of Syrian oil. This ban, which is set to take effect next month, is designed to deprive Syria of oil revenue and looks bound to further hinder its efforts to revive its oil production and expand its ailing petroleum industry. The E.U. sanctions will prevent roughly 100,000 bbl/d of mostly heavy, sour Syrian crude exports from reaching their traditional European markets. U.S. sanctions will preclude that oil from being redirected towards the United States.

European importers of Syrian crude will need to source alternative supplies, which could indirectly affect U.S. sour crude markets. Recently, sour crude markets in Europe have shown exceptional strength, with prices for Russian Urals, one of the region's main sour crude streams, swinging to an unusual premium to those for light, sweet Brent. Following reduced loading programs at Russia's Baltic Sea port of Primorsk, a key Urals export terminal, the sanctions may further support this Urals premium. Sanctions targeting Syrian exports, however, may not necessarily disrupt Syrian crude production, which so far, in contrast with the situation in Libya, has been unaffected by civil unrest. Should Syria continue to produce crude, the effects of sanctions will be different than if that crude was taken off the market altogether. Syrian exports will likely find other markets, possibly in Asia, where they might help replace exports from Yemen disrupted by civil unrest.

While the situation in Syria raises many concerns, its direct implications for international oil markets are of a different order of magnitude than those surrounding the situation in Libya that was most recently reviewed last week.

Read more about : Syria Energy Report 

Sunday, September 25, 2011

Ecuador Energy Report

Ecuador is one of Latin America's largest oil exporters, with net oil exports estimated at 285,000 barrels per day (bbl/d) in 2010. The oil sector accounts for about 50 percent of Ecuador's export earnings and about one-third of all tax revenues. Despite being an oil exporter, Ecuador must still import refined petroleum products due to the lack of sufficient domestic refining capacity to meet local demand. As a result, the country does not always enjoy the full benefits of high world oil prices: while these high prices bring Ecuador greater export revenues, they also increase the country's refined product import bill.


The economy of Ecuador is based mostly on exports of bananas, oil, shrimp, gold, other primary agricultural products and money transfers from nearly a million Ecuadorian emigrants employed abroad. ,Oil accounted for about half of public sector revenue and 40% of export earnings. Ecuador is the world's largest exporter of bananas ($936.5 million in 2002) and a major exporter of shrimp ($251 million in 2002). Exports of nontraditional products such as flowers ($291 million in 2002) and canned fish ($333 million in 2002) have grown in recent years. Industry is largely oriented to servicing the domestic market.








In 2007, Ecuador re-joined the Organization of the Petroleum Exporting Countries (OPEC), after leaving the organization at the end of 1992. Ecuador is the smallest oil producer in OPEC, with an assigned production quota of 434,000 bbl/d. Despite an increasingly challenging investment environment, data available indicate that Ecuadorian production is increasing in 2011. A growing share of Ecuador's exports are going to China, which has secured fixed supply in exchange for loans from the China Development Bank.








Ecuador's energy mix is largely dependent upon oil, which represented three quarters of the country's total energy consumption in 2008. Hydroelectric power represented 22 percent of total energy consumption in 2008, and accounts for about two thirds of power generation.


While urban electrification rates are close to 100 percent, droughts in late 2009, affecting the Paute River hydroelectric plant, caused the government to implement rolling blackouts from November 2009 to January 2010. Capacity shortages have again raised the risk of blackouts for the upcoming dry season from November 2011 to March 2012. To address this issue in the longer term, Ecuador plans to build six new hydroelectric power plants in the coming decade. Financing for all of the new projects will come from China.


Oil


According to Oil and Gas Journal (OGJ), Ecuador held proven oil reserves of 6.51 billion barrels in January 2011 –the third largest reserves in South America after Venezuela and Brazil. Ecuador is the fifth-largest producer of oil in South America, producing 486,000 bbl/d of oil in 2010 (almost all of which was crude oil), down from a 2006 peak of 536,000 bbl/d. Data from the first half of 2011 show a rebound in production, which averaged 501,000 bbl/d through June.





In 2010, Ecuador consumed 201,000 bbl/d of oil, leaving 2010 net exports of 285,000 bbl/d. In 2010, Ecuador exported 212,000 bbl/d of oil to the United States, accounting for less than two percent of total U.S. oil imports. Other destinations for Ecuadorian crude in 2010 included Chile, Peru and China. Ecuador has begun to look towards the Asian market, namely China, as an alternative export market and source of investment.


Since 2009, Ecuador has agreed to three separate loan agreements with China which were explicitly backed by oil deliveries. Under these agreements, Ecuador is required to invest a share of the loaned amount in infrastructure projects involving Chinese companies and repay the loans in crude oil shipments. In addition to these formal arrangements, China has made numerous other large-scale loans to Ecuador that have coincided with oil supply agreements.


Sector Organization


Petroecuador, the state-run oil company, controls most of the crude oil production in the country. Major foreign-owned oil companies operating in Ecuador include Repsol-YPF, Eni, and Andes Petroleum, a consortium of Chinese companies.


In November 2010 the government of Ecuador completed renegotiating its contracts with oil companies under a new hydrocarbons law. The new law mandates “service agreements,” in which oil companies will receive a fixed fee per barrel rather than shares of production, with the remainder of the revenue accruing to the government. This measure, designed to increase government revenue, led companies such as Petrobras and Noble Energy to exit the country. Negotiations over fair compensation for their assets continue.


These changes to Ecuador's legal framework continue a trend towards nationalist policies in the oil sector. In 2006, Petroecuador took over the production assets of Occidental Petroleum as a result of expired contracts and in 2009, following a tax dispute, the government also appropriated two blocks belonging to Perenco. Most recently, in February 2011, an Ecuadorian court ordered Chevron to pay $8.6 billion in damages to indigenous Ecuadorians harmed by Texaco's Ecuadorian operations between 1964 and 1990. Chevron is appealing.


Exploration and Production


Ecuador's most productive oil fields are located in the northeast corner of the country. Crude oil production increased sizably in 2003 with the opening of the Oelducto de Crudos Pesados (OCP) pipeline, which removed a chokepoint on crude oil transportation in the country (see below). However, production has leveled off in recent years, the result of natural decline, the lack of new project development, and operating difficulties at existing oil fields. Production levels have again surpassed 500,000 bbl/d in 2011 with the inauguration of the Panacocha field in the Ecuadorian Amazon – the first new production expansion since the current government took office in 2007.





Ecuador aspires to produce 600,000 bbl/d by 2013. To facilitate this expansion, Petroecuador is in the process of negotiating contracts with Schlumberger, Baker Hughes, Halliburton, and the Ecuadorian service company Sertecpet to carry out enhanced oil recovery projects in some of the country's large, mature fields that have been declining in recent years. Ecuador also plans to solicit bids to develop twelve blocks on the country's border with Peru in October of 2011.


In the longer term, production increases could come from the Ishpingo-Tambococha-Tiputini (ITT) Block located in the Yasuní National Park, which holds 850 million barrels of proven reserves. This development will be delayed in the near term due to a 2010 agreement between government of Ecuador and the United Nations Development Program (UNDP) in which the international community will pay Ecuador US $350 million per year for 10 years for not developing the ITT Block and preserve the park. Uncertainty surrounds the status of the agreement.


Pipelines


Ecuador has two major oil pipeline systems. The first is the Sistema Oleducto Trans-Ecuatoriano (SOTE), built in the early 1970s. The 310-mile, 400,000-bbl/d SOTE runs from Lago Agrio to the Balao oil terminal on the Pacific coast. The second oil pipeline is the Oleducto de Crudos Pesados (OCP). The 300-mile, 450,000-bbl/d OCP mostly parallels the route of the SOTE. The OCP began operations in September 2003, and its completion immediately doubled Ecuador's oil pipeline capacity and facilitated increases in production


Ecuador utilizes one international pipeline, the TransAndino. The 50,000-bbl/d pipeline connects Ecuador's oil fields with the Colombian port of Tumaco. The TransAndino pipeline has occasionally been the target of rebel forces in Colombia. Although the security environment has improved in recent years, the pipeline has been compromised as recently as February 2011.


Downstream Activities


According to OGJ, Ecuador has three oil refineries, with a combined capacity of 176,000 bbl/d. The largest refinery in Ecuador is Esmeraldas (110,000 bbl/d), located on the Pacific coast. Despite its status as a crude oil exporter, Ecuador is a net importer of refined oil products. In general, Ecuador exports heavy refined products, like fuel oil, and imports lighter products, such as gasoline, diesel, and liquefied petroleum gas (LPG), which dampens the country's benefits from high oil prices.


The Ecuadorian government is actively seeking ways to increase domestic production of lighter petroleum products. These plans include upgrading the Esmeralda refinery to operate at full capacity and better handle Ecuador's heavy domestic crude production. South Korea's SK Engineering is currently under contract to repair, overhaul and upgrade the Esmeraldas refinery, which had to be shut down last year following a major leak.


There have also been discussions between Ecuador and Venezuela about the construction of a new refinery in Ecuador. The two countries established a joint company to build the facility on the Pacific Coast in Manabi province with crude distillation capacity of the refinery at 300,000 bbl/d. Only a small portion of the project has been completed to date due to lack of external financing. According to recent industry reports China's Sinopec might fund a portion of the project.


Natural Gas


According to OGJ, Ecuador had 282 billion cubic feet (Bcf) of natural gas reserves as of January 2011. In 2009, Ecuador produced total of 49 Bcf of natural gas, almost all of which was associated gas from oil production. Ecuador's natural gas utilization rates are due mainly to the lack of infrastructure to capture and market natural gas. According to the National Oceanic and Atmospheric Administration, Ecuador flared the second largest amount of natural gas in South America behind Venezuela.


The only large-scale natural gas project in Ecuador is the Amistad field, located in the Gulf of Guayaquil, which produces an estimated 23.5 million cubic feet per day (MMcf/d). Petroecuador took over this project after U.S.-based Noble Energy opted to exit the country rather than renegotiate its production contract. All of Amistad's natural gas production flows to the Machala facility, a 130-megawatt (MW), onshore, gas-fired power plant that supplies electricity to the Guayaquil region.

Saturday, September 24, 2011

Ruby Pipeline


Natural gas flows on the Ruby Pipeline (Ruby) have ramped up rapidly since the start of commercial operations on July 28, 2011. Ruby, a new high-pressure, 680-mile natural gas pipeline that links Wyoming natural gas supplies mainly to markets in California, currently delivers about 0.8 billion cubic per day (Bcfd) of natural gas to an interconnect with Pacific Gas & Electric (PG&E)—the major distributor of natural gas and retail power in Northern California—and provides about 30% of PG&E's 2.5 Bcfd of average daily system supply of natural gas.

PG&E's overall natural gas needs have changed little since late July when Ruby began flowing natural gas. However, Ruby's share of total natural gas supplied to PG&E rose from less than 0.1 Bcfd to over 0.8 Bcfd in a little over a month. Increasing flows from Ruby to PG&E have displaced natural gas delivered to Northern California by the Gas Transmission Northwest (GTN) pipeline (see chart below). Flows on GTN in early July were over 1.8 Bcfd; by mid-September GTN's flows sank to about 1.0 Bcfd. Natural gas flows on other pipelines such as El Paso Natural Gas, Southern Trails, and Transwestern have not varied as much following the advent of Ruby.



 


El Paso Corporation's Ruby Pipeline (Ruby), the largest natural gas pipeline project dedicated to serving the Western United States since the expansion of the Kern River system in 2003, received approval from the Federal Energy Regulatory Commission (FERC) to commence service on July 28, 2011. Initial scheduled volumes on Ruby's mainline heading west were about 65 million cubic feet.

Ruby transports natural gas from the Opal Hub in Wyoming west through Utah and Nevada and terminates at pipeline interconnects near Malin, Oregon. The initial design capacity of the 680-mile, 42-inch transmission pipeline is up to 1.5 billion cubic feet per day (Bcfd), increasing the regional capacity to move gas from the Rockies region to the West by over 50%. Ruby greatly enhances the ability to deliver natural gas into Northern California.

On July 30, 2010, Ruby received FERC approval to begin construction, which commenced the following day. The estimated in-service date for Ruby was Spring 2011, but project delays such as the onset of the nesting season for certain migratory birds slowed construction.

On July 11, 2011, Ruby requested authorization from FERC to commence service at a lowered Maximum Allowable Operating Pressure (MAOP): 10% lower than its designed MAOP. The reduced MAOP allowed Ruby flexibility to commence service prior to receiving approval from the
Pipeline and Hazardous Material Safety Administration (PHMSA), which is required to flow natural gas at higher operating pressures.

Even at reduced pressure, Ruby will be able to fulfill its current firm capacity contract commitments of 1.2 Bcfd. Subsequently, Ruby will seek FERC authorization to raise its MAOP to the 1440 psig (pound-force per square inch gauge) level after Ruby obtains PHMSA's approval.








When U.K. became a net importer of natural gas and oil?

The United Kingdom (U.K.) is the largest producer of oil and second-largest producer of natural gas in the European Union. Due to steadily declining production since the early 2000s, the U.K. became a net importer of natural gas and oil in 2004 and 2005, respectively.

In 2010, the U.K. produced 1.4 million barrels per day (bbl/d) of oil and consumed 1.6 million bbl/d. While consumption remained relatively constant throughout the last decade, 2010 production declined 7% from 2009. Further declines are expected: the U.S. Energy Information Administration's Short-Term Energy Outlook predicts the U.K.'s production will fall to 1.2 million bbl/d in 2012. Despite decreasing production, the U.K. remains one of the European Union's leading petroleum exporters; in 2010, the U.K. exported 832,000 bbl/d, more than half of its total production.


In 2010, U.K. natural gas production was 2.0 trillion cubic feet, a 5% drop from 2009, and the lowest level since 1992. Natural gas consumption rose 7% in 2010. To offset its declining natural gas production in the North Sea, the U.K. is importing more liquefied natural gas (LNG). Deliveries of LNG to the U.K. were up 0.86 billion cubic feet per day, or 54%, during the first nine months of 2011 compared to the same period in 2010.

Because discoveries of new oil and natural gas reserves have not outpaced the maturation of existing oil and natural gas fields, production from both has declined. The U.K.'s increasing reliance on imported natural gas and oil has spurred the government to develop energy policies to focus on enhanced oil and gas recovery, as well as increased cooperation with Norway—U.K.'s largest oil supplier. The U.K. has also invested heavily in renewable energy; according to the U.K. Department of Energy and Climate Change, the U.K. has the largest offshore wind resource in the world.


UK Shale gas discovery
UK Energy Report

Friday, September 23, 2011

Proved Oil Reserves


Global oil reserves rose by 6.6 billion barrels to 1,383 billion barrels in 2010. In 2010, increases in India, Brazil, Russia, Uganda, Columbia, and Ghana outpaced declines in Mexico and Norway. The 2009 figure was revised higher by 44 billion bbls, due to large upward revisions in Venezuela of 39 billion bbls and smaller increases in Russia, the US, and Libya. At the end of 2010 the global R/P ratio was 46.2 up from 40.3 ten years prior.



Thursday, September 22, 2011

Global Biofuels Production

Global biofuels production in 2010 grew by 13.8%, or 240,000 b/d, constituting one of the largest sources of liquids production growth in the world. Growth was driven by the US (+140,000 b/d, or 17%) and Brazil (+50,000 b/d, or 11.5%). Renewable energy used in power generation grew by 15.5%, driven by continued robust growth in wind energy (+22.7%). 




Supply increased for the tenth year in a row as ethanol output reached 43.5 mtoe (1.5 mb/d) and biodiesel production hit 15.8 mtoe (0.4 mb/d). Ethanol production accelerated by 16% compared to 9% in 2009, while biodiesel growth slowed to 9% compared to growth of 24% the previous year.The US and Brazil continue to dominate global ethanol production with market shares of 56% and 32% respectively. Growth rates accelerated in 2010 from the previous year as the US grew by 21% versus 18% and Brazil expanded by 8% after falling 4%. The biodiesel market is much less concentrated than that of ethanol, but also much smaller, contributing less than a third of total biofuel production. The largest producers are Germany, France, Brazil, and Argentina – all with 10-14% market share. Europe dominates production with 59% of the total, while the US contributes only 6%.



Wednesday, September 21, 2011

Huge UK Shale Gas Resources discovered



UK junior Cuadrilla Resources today claimed it is sitting on 200 trillion cubic feet (cf) of shale gas from just two wells drilled in northwest England. Cuadrilla’s shale gas estimate dwarfs Norway’s huge Troll gasfield, which has recoverable reserves of 33 trillion cf, and Ormen Lange, which holds 8.6 trillion cf of recoverable gas. And it even overshadows the 187 trillion cf of technically recoverable shale-gas reserves that the US Energy Information Administration believes Poland possesses.



The decline in production from the North Sea has seen the UK become a net importer of gas since 2004 and of crude oil since 2005. This means that the country is set to become increasingly reliant on international energy markets to meet its energy needs – leaving the country vulnerable to price volatility and disruptions in supply.



Cuadrilla hopes to start commercial production by mid-2012. The company, which has been exploring for shale gas at sites near Preston in Lancashire and Bank, near Liverpool, has drilled two wells so far and is in the process of drilling another.

“We’re excited,” Dennis Carlton, Cuadrilla’s executive director told PEU. “It’s a significant number [200 trillion cf], but we need to refine it and make sure we can quantify it.”

Cuadrilla explained this was an estimate for gas in place, not necessarily ultimately recoverable volumes. The company said it would not know exactly how much gas could be recovered until it had finished exploration phase and the results had been analysed. This would likely be next summer.

It plans to drill five to six wells in the next year and that ultimately around 10 wells would be needed to confirm the initial resource estimate, which was calculated by the company itself.

Tremors

Cuadrilla’s Grange Hill site is shut in pending the results of an investigation by the department of energy and climate change (Decc) following two tremors at the firm’s drilling sites earlier this year. Some environmentalists claimed the tremors could have been caused by Cuadrilla’s hydraulic fracturing (fracking) operations in the area, a charge Cuadrilla denies.

The firm, which has been unable to frack since the investigation started, said the report should be released by mid-October. If Decc concludes that the tremors are the result of fracking, it could potentially halt the company’s shale-gas aspirations in Lancashire.

However, Carlton told PEU he is confident Decc will find in Cuadrilla’s favour. If it doesn’t, the company will concentrate on developing its other licences in the Netherlands and Poland. “To pack up and move out of the UK would be a big blow to a small company, but it was part of the game plan. For anyone with four or five projects across Europe you can guarantee that they aren’t all going to work. We’re not going to put all our eggs in one basket,” he added.

There has been some local opposition to the company’s drilling plans, including a demonstration of around 150 people near the company’s Bank site last week. When Cuadrilla chief executive Mark Miller announced the company’s 200 trillion cf estimate in Blackpool today, there was also a small group of protestors outside.

But the company is confident it will manage to convince the public that it can develop northwest England’s shale gas safely, and has also played up the potential financial benefits it could bring to the region. Miller said he wants to create an “Aberdeen effect” in Lancashire. He claimed the company could contribute £5 billion ($7.8 billion) to £6 billion to the local economy over the next 30 years through job creation and business taxes.

UK gas market turned on head

If even a fraction of Cuadrilla’s shale-gas reserves are recoverable, it would turn the UK gas market on its head. This includes drastically reducing UK imports of Norwegian and Dutch gas by pipeline, as well as liquefied natural gas (LNG) from as far away as Qatar and Nigeria.

“If they say a 200 trillion cf recoverable resource over 30 years, that's 190 billion cubic metres (cm) a year, or 500 million cm/d. Even 50% of that is double what the UK is producing today,” one UK gas trader said. This would be enough to meet the whole of the UK gas demand in the peak winter period, with consumption usually around 400 million cm/d.

Cuadrilla’s shale gas estimate dwarfs Norway’s huge Troll gasfield, which has recoverable reserves of 33 trillion cf, and Ormen Lange, which holds 8.6 trillion cf of recoverable gas. And it even overshadows the 187 trillion cf of technically recoverable shale-gas reserves that the US Energy Information Administration believes Poland possesses


But some UK gas traders were sceptical about whether the mid-2012 production start date would produce volumes sufficient to affect prices.

“It’s nice to say, but hard to promise,” one UK gas trader said. “The planning rules are bit different [in the UK] to the US, which makes it harder to access the gas,” another said.

The UK has been importing more and more gas to meet rising demand as North Sea gas production has gone into decline. LNG imports now account for around 25% of UK consumption.

Petroleum Economist, 21 September 2011

Related Topic :Uk: New Oil İmporter

Potential Shale Gas and Shale Oil Resources of the Norte Basin


Introduction

The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of State, is assessing the potential for unconventional oil and gas resources (shale gas, shale oil, tight gas, and coalbed gas) in priority geologic provinces worldwide. The authors summarize the geologic model and results of an assessment of
potential shale gas and shale oil resources of the Norte Basin, Uruguay. The Norte Basin of Uruguay is the southern extension of the Paraná Basin of Brazil (fig. 1), and is largely covered by volcanic rocks. The main geologic structures in the basin are interpreted to be northwest-southeast trending grabens and horsts, which, if present, control the distribution of Devonian-age shale and oil and gas resources in the basin.




Devonian Shale System in the Norte Basin

The Devonian Cordobes Formation is interpreted to be the principal petroleum source rock in the Norte Basin and possible reservoir for shale gas and shale oil accumulations. The geologic attributes of the Cordobes Formation relevant to the assessment are inferred from outcrops along the southern margin of the Norte Basin (Conti and Morales, 2009; ANCAP, written commun., 2011). Thickness of the Cordobes ranges up to 160 meters (m), including as much as 60 m of organic-rich shale. Total organic carbon concentration ranges from 0.7 to 3.6 weight percent. The organic matter is predominantly Type II marine kerogen, with a contribution from Type III kerogen. Thermal maturity at outcrop averages 0.6 percent vitrinite reflectance, suggesting thermal maturity corresponding to the onset of oil generation. Basin modeling suggests that thermal maturity necessary for oil-to-dry gas transition in the Devonian is at a depth of about 3,200 m (ANCAP, written commun., 2011), which was used as the boundary between potential shale oil and shale gas accumulations in the assessment (fig. 1). Given what is known of the thermal maturity, this boundary is uncertain.

Geologic Model for Assessment

The geologic model used in the assessment of the Norte Basin assumes oil and gas to have been generated in organic-rich shales of the Devonian Cordobes Formation and to occupy matrix porosity and organic porosity in the same shales. The thermal window for gas was modeled to begin at about the 3,200-m depth, with oil as the main petroleum phase at shallower depths. Devonian shales most likely are present beneath the volcanic cover in northwest-southeast trending grabens that have been imaged with geophysical methods. The presence of Devonian organic-rich shale in the grabens, the potential matrix storage of oil or gas, and the thermal windows for oil in relation to gas are subject to significant geologic uncertainty. Shale gas and shale oil accumulations in the United States were used as geologic and engineering analogs in the assessment. Analog data from U.S. accumulations included estimated ultimate recoveries (EUR) from shale gas and shale oil wells, mean drainage areas of wells (cell sizes), and ranges of well success ratios.

Key assessment input data are listed in table 1.

Resource Summary
The USGS assessed potential technically recoverable shale gas and shale oil resources in the Norte Basin of Uruguay, resulting in total estimated mean resources of 13,361 billion cubic feet of gas (BCFG), 508 million barrels of oil (MMBO), and 499 million barrels of natural gas liquids (MMBNGL) (table 2). Of these totals, the estimated mean resource volumes are (1) Devonian Cordobes Formation Shale GasAU,11,328BCFG(range from 0 to 24,042 BCFG), and 453 MMBNGL range from 0 to 1,002 MMBNGL); and (2) for the Devonian Cordobes Formation Shale Oil AU, 508 MMBO (range from 155 to 1,081 MMBO), and 2,033 BCFG associated gas (range from 574 to 4,521 BCFG), and 46 MMBNGL (range from 12 to 106 MMBNGL). The ranges of resource estimates, particularly those for shale gas (0 to 24,042 BCFG), reflect the considerable geologic uncertainty in these assessment units.


Tuesday, September 20, 2011

OPEC Share of World Crude Oil Reserves

According to current estimates, more than 80% of the world's proven oil reserves are located in OPEC Member Countries, with the bulk of OPEC oil reserves in the Middle East, amounting to 65% of the OPEC total. OPEC Member Countries have made significant additions to their oil reserves in recent years, for example, by adopting best practices in the industry, realizing intensive explorations and enhancing recoveries. As a result, OPEC's proven oil reserves currently stand at well above 1,190 billion barrels.





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Brazil: The world’s next major oil producer?

In 2007, a consortium led by Petrobras, Brazil’s national oil company, discovered the Tupi field in the Santos Basin off the coast of Brazil. The field, now known as a “pre-salt deposit,” was found 18,000 feet below the ocean surface underneath a 6,000-foot layer of salt. Tupi and other pre-salt finds hold the potential to make Brazil one of the world’s most prolific oil exporters. Although Brazil already produces 2.1 million barrels per day of crude oil and lease condensate, it did not become a net exporter until 2009. In the next decade, Brazil aspires to more than double its conventional production and significantly expand its oil exports.


Read more at : Brazil Energy Report


According to Oil & Gas Journal, Brazil’s proven oil reserves are estimated currently at 12.9 billion barrels, not including major presalt fields. Estimates of Brazil’s pre-salt reserves have varied widely. In 2008, Haroldo Lima, Director General of Brazil’s National Petroleum Agency, stated that the country’s pre-salt deposits could contain between 50 and 70 billion barrels of oil. More recently, in January 2011, Petrobras announced its assessment that the Tupi and Iracema fields (renamed Lula and Cernambi) contain 6.5 billion and 1.8 billion barrels of commercially recoverable oil, respectively . It will be some time before the Brazil’s pre-salt reserves are fully quantified, but knowledge of exact reserve levels is not critical to assessing the viability of Brazil’s proposal to expand their production in the coming years.






In its 2010-2014 business plan, Petrobras outlined production targets of 3.0 million barrels per day in 2014 and 4.0 million barrels per day in 2020. In the plan, more than one-quarter of the company’s Brazilian production in 2020 comes from pre-salt fields.


In the IEO2011 Reference case, Brazil’s conventional liquids production increases to 3.3 million barrels per day in 2020 and 4.9 million barrels per day in 2035; and its total liquids supply, including unconventional liquids such as ethanol and biodiesel, increases to 6.6 million barrels per day in 2035. The projections reflect a somewhat more conservative view of the pace of expansion, given the financial, regulatory, and operational challenges that Petrobras will need to overcome in order to realize the full potential of Brazil’s pre-salt resources.




Financing the development of pre-salt oil fields will be expensive. One analyst has suggested that Brazil’s current undertaking could be “the largest private sector investment program in the history of mankind [53].” The Petrobras business plan includes investments of $224 billion between 2010 and 2014, more than half of which will be spent on exploration and production activities. To facilitate the plan, the company raised $67 billion in the world’s largest initial public offering ever in September 2010. However, most of the capital came in the form of a reserves-for-shares swap with the Brazilian government [54]. Petrobras will need to fund the majority of its investments through operating cash flow. The increase in the government’s equity points to an expansion of state involvement in the petroleum sector.


The government’s capitalization of Petrobras was part of a set of laws passed in 2010 to regulate development of Brazil’s pre-salt reserves. The legislation also established a new federal agency (Petrosal) to administer pre-salt production and set up a fund to align the expenditure of pre-salt revenues with Brazil’s development goals. Most importantly in terms of Brazil’s investment climate, the law changed the country’s concession-based system for exploration to a production-sharing agreement (PSA) system.






Under the PSA system, Petrobras will hold at least a 30-percent share of each project and be the operator . Some analysts fear that the new system will reduce foreign interest in investing in Brazil and overburden Petrobras. The re-launch of Brazil’s latest bid round for oil exploration blocks is scheduled for 2011, pending settlement of a dispute over the distribution of pre-salt royalties among Brazilian states. The results of the bid round will highlight the full impact of the legislative changes on the development of pre-salt resources. Development of pre-salt deposits represents a daunting task, with considerable technological uncertainty about how the geologic formations will behave once production has begun. In addition, the reserves are located more than 150 miles off Brazil’s coast, making them difficult for pipelines and people to reach. Petrobras plans to purchase 45 floating production, storage, and offloading (FPSO) vessels to extract the pre-salt oil; however, only 75 such rigs currently exist in the world .


In addition to massive investments in physical capital, the planned expansion of Brazil’s production will require additional human capital. Petrobras plans to train 243,000 technical professionals to work in the petroleum industry in the coming decade and to invest hundreds of millions of dollars in oil-related research and development centers at Brazilian universities . Given the scale of the task, the predominant role played by Petrobras, and local-content requirements, operational challenges introduce a nontrivial amount of uncertainty into projections of Brazil’s liquids production. Brazil’s pre-salt discoveries represent some of the most promising oil finds, and its role as an oil producer will grow in the coming decades. The extent of that expansion