With proven reserves of 910 trillion cubic feet (Tcf), Qatars natural gas resources rank third in size behind Russias and Irans. Most of Qatars natural gas is located in the offshore North Field, which is the largest known non-associated natural gas field in the world. In addition, the onshore Dukhan field contains an estimated 5 Tcf of associated and 0.5 Tcf of non-associated gas. Smaller associated gas reserves also are contained in the Id al-Shargi, Maydan Mahzam, Bul Hanine, and al-Rayyan offhore oil fields. The Qatari government believes that the countrys economic future lies in developing this vast natural gas potential.
Qatar exports almost all of its oil production to Asia, with Japan by far its largest customer. In 2005, net oil exports totaled 1,047,000 barrels per day (bbl/d). During this period, Qatar produced 1,087,000 bbl/d of liquids (including crude oil, natural gas liquids, and condensate), up slightly from 1,069,000 bbl/d in 2005. Qatar also produces a significant amount of lease condensate and other natural gas liquids (NGLs), both of which fall outside the countrys OPEC crude oil production quota, which has been set at 700,000 bbl/d since November 1, 2004. Production on NGLs has been rising as a byproduct of increased natural gas production. Following the coup in 1995, Qatar initiated a number of new policies aimed at increasing oil production, locating additional oil reserves before existing reserves become too expensive to recover, and investing in advanced oil recovery systems to extend the life of existing fields. To accomplish this, the government in recent years has improved the terms of exploration and production contracts and production sharing agreements (PSA). The improved terms are designed to encourage foreign oil companies to improve oil recovery in producing fields and to explore for new oil deposits. Foreign companies now account for more than one-third of Qatars oil production capacity.
Qatar has proven recoverable oil reserves of 15.2 billion barrels. The onshore Dukhan field, located along the west coast of the peninsula, is the country largest producing oilfield. Qatar also has six offshore fields, Bul Hanine, Maydan Mahzam, Id al-Shargi North Dome, al-Shaheen, al-Rayyan, and al-Khalij. Qatari crude oil has gravities in the 24º-41º API range. The countrys two primary export streams are Dukhan (41º API) and Marine (36º API) blend. Despite the countrys significant oil production and reserves, oil accounts for less than 15 percent of domestic energy consumption.
Qatars policy of economic diversification has led to a surge in investment in projects for the export of LNG and petrochemicals. Qatars real gross domestic product (GDP) is projected to increase 6.6 percent in 2006, after growth of 6.3 percent in 2005. High oil prices, combined with rising sales of liquefied natural gas (LNG), have led to an economic boom in Qatar. Qatars oil production rose slightly in 2005, reaching 1,087,000 barrels per day. Qatar has proven recoverable oil reserves of 15.2 billion barrels. The onshore Dukhan field, located along the west coast of the peninsula, is the country largest producing oilfield. Qatar also has six offshore fields, Bul Hanine, Maydan Mahzam, Id al-Shargi North Dome, al-Shaheen, al-Rayyan, and al-Khalij. The improved terms are designed to encourage foreign oil companies to improve oil recovery in producing fields and to explore for new oil deposits. Qatar Petroleum and Cosmo Oil concluded a contract in October 2003 for the development of two small offshore oil deposits, Al-Karkara and A-North. Production from seven wells, four in Al-Karkara and three in A-North, began in 2005, and currently is about 10,000 bbl/d. In November 1997, Chevron Phillips Chemical Company signed a $1.1 billion deal with Qatar Petroleum to build a petrochemical plant, Q-Chem, which was completed in 2002. With the worlds third-largest natural gas reserves, Qatar has become a major exporter. With proven reserves of 910 trillion cubic feet (Tcf), Qatars natural gas resources rank third in size behind Russias and Irans. Qatar has two liquefied natural gas (LNG) exporters: Qatar LNG Company (Qatargas); and Ras Laffan LNG Company (Rasgas). The two major shareholders in the project are Qatar Petroleum and ExxonMobil.
In addition to increasing reserves and production, Oman would like to enlarge its existing pipeline network and is using foreign construction companies to do so. In 2002, contractors completed two lines to connect the reserves in the middle of the country to the coast. One cost $124 million and connects with Sohar. The other cost $180 million and connects with Salalah. There is also an older 500-mile gas trunk line connecting the central fields with power plants and the processing facility of the Oman Liquefied Natural Gas Company (OLNGC), a consortium whose shareholders are the Omani government (51 percent), Shell (30 percent), Total (5.54 percent), and Korea LNG (5 percent), Mitsubishi (2.77 percent), Mitsui & Co. (2.77 percent), Partex (2 percent), and Itochu (0.92 percent). Oman is one of the participants in the $3.5 billion Dolphin project being led by Dolphin Energy Limited (DEL, a joint-venture between the UAE government, Total, and Occidental Petroleum). The goal is to link the gas networks of Qatar, the UAE, and Oman. Under a deal reached in March 2003, OGC began supplying gas to DEL in the fourth quarter of 2003. An agreement signed in September 2005 calls for the pipeline to reverse direction in 2008, as had previously been anticipated. Oman will then import 200 million cubic feet per day (MMcf/d) from DEL.
Oman is pursuing petrochemical projects as a way of diversifying its economy and developing value-added industries. In January 2001, Ferrostaal (Germany) signed a contract with the Omani government to build a methanol plant in Sohar. The deal is estimated to be worth over $420 million and is a joint venture between Ferrostaal, the state-owned Omani Oil Company, and a private Omani group, Omzest. The project will utilize some of the 5 trillion cubic feet (Tcf) of gas that the Omani government has made available to new industries in Sohar. The plant is expected to begin operation in 2005 and has a projected production capacity of 5,000 tons of methanol per day.
In many ways, Oman is atypical of Persian Gulf oil producers. Omans petroleum deposits were discovered in 1962, decades after most of those of its neighbors. Moreover, Omans oil fields are generally smaller, more widely scattered, less productive, and more costly per barrel than in other Persian Gulf countries. The average well in Oman produces only around 400 barrels per day (bbl/d), about one-tenth the volume per well of those in neighboring countries. To compensate, Oman uses a variety of enhanced oil recovery (EOR) techniques. While these raise production levels, they increase the cost.
Oman has proven recoverable oil reserves of 5.5 billion barrels, the bulk of which are located in the countrys northern and central regions. The largest and traditionally most reliable fields are in the north. These fields, which include Yibal (the biggest), Fahud, al-Huwaisah, and several others, are now mature and face future declines in production. Omans total (i.e. including condensate and other liquids) production figure fell sharply from its height of 972,000 bbl/d in 2000 to 754,000 bbl/d in 2004. In 2005, however, output recovered slightly, averaging 780,000 bbl/d, as a result of the introduction of additional EOR measures, as well as increased production of natural gas liquids. If output continues at the present pace and no major new reserves are discovered, Oman has less than 20 years left as a significant oil-exporting nation. Given estimates suggesting that the amount of oil originally in place in Oman is around 50 billion barrels, finding ways to increase recoverability is a top priority. As part of its attempts to expand its reserves, in 2003 Oman signed a six-year contract with Spectrum Energy and Information Technology (UK) to have old seismic studies reprocessed.
Omans real gross domestic product (GDP) grew by 4.6 percent in 2005. Omans efforts to diversify the economy also include Omanization, a program designed to increase the percentage of Omani citizens working in the private sector. Omans macroeconomic environment currently is strong, despite recent declines in oil production. Omans oil production rose in 2005, reversing several years of declines. In 2003 Oman signed a six-year contract with Spectrum Energy and Information Technology (UK) to have old seismic studies reprocessed. Omans third LNG train began operation in January 2006, boosting export capacity by 50 percent. Union Fenosa has a 20-year contract for half of the third trains output. Other major LNG purchasers are Kogas (South Korea), Daghol Power (India), and Osaka Gas (Japan). Occasional spot cargoes also are delivered to Europe and the United States. Oman has commissioned several privately-owned power plants over the last decade. In 2003, Omans installed power generating capacity was estimated at 2.9 gigawatts (GW). With the exception of some very remote villages, the entire country is electrified.
The Democratic Peoples Republic of Korea (North Korea) occupies a strategic location bordering China, South Korea, and Russia. North Koreas communist ideology has been based on the concept of juche, or self-reliance. The designation of North Korea as a state supporter of terrorism by the United States also effectively precludes lending by international financial institutions such as the World Bank. North Korea relies on coal and hydropower for most of its energy needs. North Korea relies on two domestic sources of commercial energy -- coal and hydropower -- for most of its energy needs. North Korea lacks domestic oil reserves. North Korea lacks domestic petroleum reserves, but the West Korea Bay may contain hydrocarbon reserves, as it is considered to be a geological extension of Chinas Bohai Bay. North Korea is a potential transit route for natural gas to South Korea. South Korea has held discussions with China, Russia, and BP about the possibility of importing natural gas from Russias huge Kovykta gas field near Irkutsk. Six party talks, including the United States, North Korea, South Korea, China, Russia, and Japan, have sought to end North Koreas nuclear weapons program. Japan signed a contract in May 1999 committing to provide its $1 billion contribution to KEDO to fund the new light-water reactors, an action which had been delayed by North Koreas missile test in August 1998.
During 2004, Azerbaijan exported approximately 211,000 bbl/d, but exports are expected to more than double to 478,000 bbl/d in 2006 and reach as high as 1.1 million bbl/d by 2008 according to Azeri government estimates. Implicitly, the government estimates assume additional production from new offshore discoveries as well as the modernization of old fields. On May 25, 2005 Azerbaijan began filling the Azeri section of the long-awaited Baku-Tblisi-Ceyhan (BTC) pipeline that runs 1,040 miles from the Azeri capital city of Baku, via Georgia, to the Mediterranean port of Ceyhan. At a cost of almost $4 billion, the BTC pipeline allows oil to bypass the crowded Bosporus andDardanellesStraits.. Test filling began in early May 2005, and the BP-led consortiumloaded its first tanker on July 13, 2006. Currently, Azerbaijans other export routes are the Baku-Novorossiysk pipeline (northern route), which sends approximately 50,000-90,000 bbl/d of Azeri (and exclusively SOCAR) crude oil to the Russian Black Sea. The Baku-Novorossiysk pipeline closed briefly in late June 2004 after oil thieves set off an explosion when they attempted to steal oil from the pipeline. The Azeri state company began reducing oil exports via the Baku-Novorossiysk pipeline in August 2005 in order to divert crude to the BTC line, once it becomes operational. Some Azeri government officials have hinted that SOCAR will stop using the Novorossiysk route once BTC becomes fully operational because it will no longer be economic to have higher quality Azeri crude oil mixing with Russian-based Urals blends. The crude oil mixing has decreased the price of pure Azeri light at the port of Novorossiysk by as much as $4-5 per barrel. AIOC will, however, continue to export oil via pipeline and rail from Baku to Supsa (also called the Western early oil pipeline) and to Batumi on the Georgian Black Sea coast. (see Map 2, PDF, high Res). The Baku-Supsa line has an estimated capacity of 155,000 bbl/d and the Exxon and Azpetrol rail links to Batumihas 120,000 bb/d of transport capacity. Early in June, a small pipeline was completed to allow Exxons share of ACG production to be pumped direct from BPs Sangachal terminal to the nearby Azpetrol rail tank-car terminal in Azerbaijan. Before the startup of BTC, Batumi offers shippers like Exxon the ability to keep their Azeri Light crude oil streams isolated in the rail system and maintain their price premium over the regional Russian Urals blend. ExxonMobil launched shipments in June 2005 and has since committed itself to supplying over 70 million barrels of oil over five years (roughly 40,000 bbl/d) via Batumi. The company will continue to use its 8 percent share of Baku-Supsa to which it is entitled to as an ACG shareholder. Since it is not a member of the BTC consortium, it will avoid paying some of the capital costs of the pipeline. During the summer of 2004, Iranian president Mohammad Khatami visited Baku and discussed a North-South transport corridor stretching from Russia to Iran. Although relations between Azerbaijan and Iran remain tense, Khatamis visit may lead to improved trade and economic cooperation and oil export options. During the first half of 2005, gasoline shipments averaged around 10,000 bbl/d. As more crude oil export options become feasible, Azerbaijan plans to decrease refined product shipments beginning in June to a level of around 2,800 bbl/d.