IT will take many more years and exploration deals for Algeria to develop its full potential as an oil and gas producer. The aim of state energy company Sonatrach is to achieve oil production of 1.4 million barrels a day (b/d) by 2000, up from an estimated 850,000 b/d at present.

Production has risen only slightly in 1997 as most of the big discoveries of recent years have yet to be developed. Spain’s Cepsa boosted production at the RKF field from 8,000 b/d to 20,000 b/d in July.

The biggest increase is expected from the three fields, all in block 404, operated by Anadarko of the US. The Hassi Berkine South field is to start producing 60,000 b/d in the second quarter of 1998, and production at the block should rise to 300,000 b/d by 2000. After Anadarko struck oil at the HBNS-1 well drilled in June, its ninth successful well in Algeria, it revised the reserves estimate for blocks 404 and 208 by 30 per cent to 2,000 million barrels.

Arco’s enhanced oil recovery project at Rhourde el-Baguel is progressing and should increase production five-fold by 1999 to 125,000 b/d. Development work has also started at the Tifernine field, operated by Spain’s Repsol.

More production capacity will be put in place at the ORD field, which is shared by Spain’s Cepsa, the US’ Louisiana Land & Exploration and Anadarko, and for which a joint development plan has yet to be approved.

Although new discoveries this year have not been as numerous as in 1996 – when Algeria achieved the world record for new finds – several companies have struck lucky, including Australia’s BHP, Arco and Italy’s Agip.

After the flurry of discoveries in recent years, companies are flocking to Algeria. This year, the UK’s Monument Oil & Gas farmed into the El-Ouar acreage in the Ghadames basin; BHP signed a new production sharing agreement for the Boukhechba tract north of the Illizi basin; Agip took on block 213 at the southwest edge of the Ghadames basin; and the US’ Union Texas Petroleum farmed into the Bordj Messouda concession.

Exxon and Amoco Corporation, both of the US, are understood to be in negotiation for enhanced recovery projects. The biggest gas project is still BP’s plan to develop District 3. After initial studies, BP is confident it can produce 9-11 billion cubic metres (bcm) a year. The exploration and appraisal phase will take until the end of 1998.


The Egyptian economy is experiencing a purple patch at the moment, and the oil and gas sector is no exception. True, oil production has declined, but exploration is booming, and a number of highly promising oil finds have been made in recent months. Gas production is poised to double over the next four to five years as the series of major recent discoveries are developed and brought on stream.

Crude oil output fell by 2 per cent to 21 million tonnes (roughly 840,000 barrels a day – b/d) in the first half of 1997, compared with January- June 1996. Over the previous 10 years, production had been in the range of 870,000-900,000-b/d, and so the fall off since the end of 1995 has caused concern.

The main reason for the drop has been reduced volumes from the powerhouse of the oil industry, the fields operated by Gulf of Suez Petroleum Company (Gupco). The joint venture between Amoco of the US and the Egyptian General Petroleum Corporation (EGPC) has operated a string of prolific oil fields in the Gulf of Suez since the 1960s. production has been tapering off in recent years. Gupco’s fields in this area produced about 330,000 b/d in January-June 1997, compared with just over 350,000 b/d in the first half of 1996.

The government is pinning its hopes on other areas compensating for the decline in Gulf of Suez output. The Western Desert promised a lot in the 1980s, and attracted substantial exploration investment. However, the area has proved to be better endowed with gas than with oil. Crude production from the three main fields – Agiba (foreign operator – Agip of Italy), Khalda (Repsol of Spain) and Badreddin (Royal Dutch/Shell) – is only just over 100,000 b/d in total.

By contrast, Badreddin is one of Egypt’s most prolific gas fields, producing over 300 million cubic feet a day (mcf/d), and Khalda and the nearby Obeiyed (Shell) will be producing 600 mcf/d in total by 2000. Egypt’s total gas production is now about 1,600 mcf/d.

Prospects for oil appear better on the fringes of the Western Desert, near the Middle Egypt town of Beni Suef. Apache of the US is producing over 60,000 b/d from the Qarun concession, and its operating partner in the nearby East Beni Suef block has just announced a promising discovery, testing at 7,000 b/d. Encouraged by the Beni Suef results, companies are now exploring further and further south, notably Apache in the Asyut area and Repsol round Aswan.

Egypt is also hoping that more oil can be found in the Gulf of Suez itself – Amoco, for example, has just announced a modest new crude discovery in Gupco’s July field. Four of the 12 blocks offered in the well-received bid round which closed at the end of September were in the Gulf of Suez, reflecting the view that this area is still far from depleted.

However, the main action is in the Delta, where Amoco, Agip and the UK’s BG are in the forefront of a major gas development programme. Amoco and Agip are starting to develop two new offshore fields – Ras el-Barr and Balteem – which will add at least 300 mcf/d to Egypt’s gas production by 2000. BG has also indicated its plans to develop the Rosetta block, where it is the operator.

Operators are also starting to look for gas further offshore in two large blocks north of many of the recent gas finds. Two more deep water blocks, further to the west, are included in a bid round that closes on 31 March 1998.

The September bid round attracted 30 offers, and EGPC says it received multiple applications for most of the 12 blocks tendered. Preliminary awards are likely to be made for most of them by the end of the year. As a result of these deals, and the rash of new permits awarded over the past two years, Egypt will be one of the active areas for oil and gas exploration for years to come.


UPSTREAM oil and gas projects offered to foreign investors by the Iranian Oil Ministry two years ago have finally become viable propositions as the US relaxes its efforts to prevent international companies entering Iran. Several projects have been cleared and more contracts should be awarded in 1998.

The Oil Ministry has been hoping to raise sustainable crude output capacity by about 10 per cent by the turn of the century. This would mean the addition of 300,000-400,000 barrels a day (b/d) to the industry’s existing capacity of 3.9 million-4 million b/d, bringing potential output closer to the officially projected target of 4.5 million b/d.

Although Iran has had little or no difficulty producing its OPEC quota of 3.6 million b/d, some Western oil experts insist that productions levels are being maintained at heavy cost to the long-term viability of producing fields. Incalculable, and possibly irreversible, damage may have been done to old fields, the experts say.

However, others say Iran appears to have sustained steady output levels with what may turn out to be minimal damage. Seriously depleting wells have been shut down, some new wells have been brought on stream and there is much more skilled maintenance work than outsiders realise, they say.

Certainly, Iran’s spare capacity will be boosted next year when the Sirri A and E offshore oilfields begin production. These are new fields being developed by France’s Total, in partnership with Malaysia’s Petronas, under a $600 million contract awarded by the National Iranian Oil Company (NIOC) in 1995. They will eventually produce 120,000 b/d.

The Sirri project was the first of the nearly one dozen schemes offered to foreign investors at the time. The contract was finalised before the US threatened secondary sanctions against international firms planning to invest more than $20 million a year in Iran’s oil and gas industry. The secondary sanctions legislation of August 1996 delayed finalisation of the remaining priority schemes by about a year.

Ignoring US threats, the Canadian oil company Bow Valley Energy completed a $200 million deal in July 1997 to develop the offshore Balal field for an output of 40,000 b/d within three years. The slightly larger nearby Soroush field has also been awarded, although financing has yet to be completed.

Expected soon is a contract of up to $1,000 million to Elf Aquitaine of France for the Doroud oil field and gas flaring reduction project. This is a scheme that was being considered by the World Bank for a $250 million loan before US pressure forced the bank to stop new loans to Iran in 1993. Doroud will be an important element in plans to use associated gas to repressurise depleting oil wells in the south.

The breakthrough for Iran’s upstream plans came in September 1997 when Total, joined in a consortium by Russia’s Gazprom and Petronas, announced a $2,000 million deal for the second and third phases of the South Pars offshore field, one of the world’s biggest gas fields, with estimated reserves of 8.5 million million cubic metres. The project is being financed on a buy-back basis over seven years from the start of production in 2001 – when 80,000 b/d of condensates will become available for export.

The South Pars deal came as US determination to enforce sanctions against Iran was flagging, and Washington’s failure is bound to encourage investors looking at Iran, OPEC’s second biggest exporter, as a more promising growth area for the future. But upstream projects on the mainland may not be opened to international developers for some time. All the projects offered to outside investors have been offshore, where there is less political sensitivity to investment by foreigners.

However, officials are suggesting that legislation is being prepared to permit foreign firms to take on enhanced recovery schemes onshore


The oil majors are carefully watching events in Kuwait after the Supreme Petroleum Council (SPC) approved plans this summer to invite foreign oil companies into production sharing agreements to help the country meet its production targets.

Current crude production in Kuwait is in line with its OPEC quota of 2 million (b/d), but Kuwait Oil Company (KOC) is aiming to boost production capacity to 3.5 million b/d by 2005, estimating that the call on Kuwaiti crude will have risen to 3 million b/d. However, over the past three years it has become apparent that KOC will not be able to meet that target without the technical assistance of foreign firms, whose role is presently confined to service agreements.

The SPC finally approved the principle of allowing production sharing contracts with foreign oil companies on 30 July. It is now considering various options for involving foreign firms in the upstream sector, and will submit a final plan for approval to Emir Sheikh Jaber al-Ahmad al- Sabah.

KOC is understood to have ruled out any form of production sharing or concession agreement. Oil companies will be offered a form of service contract and be paid in cash rather than oil for their assistance.

Not all Kuwait’s oil fields will be open to outsiders. It is likely that agreements will be initially limited to the Sabriya and Rawdatain fields in the north. The giant Burgan field, which produces 1.5 million b/d, is likely to be permanently out of bounds.

Production at the Rawdatain field is set to be boosted with the construction of gathering centre (GC) 25 and new water injection facilities. South Korea’s Daelim Industrial Company was awarded a KD 38.82 million ($128 million) contract to build GC 25 while Italy’s Snamprogetti is supplying and installing the water injection facilities at a cost of KD 29.09 million ($96.08 million). Both contracts were awarded in June.

GC 25 is expected to be the last gathering centre to be built this century. However, KOC is expected to press ahead with other enhanced recovery schemes at the Minagish, Sabriyah and Bahra fields over the next three years.


SANCTIONS have not prevented Libya from pushing ahead with plans to boost its oil production. Current capacity is close to Libya’s OPEC quota of 1.39 million of barrels a day (b/d), and is set to rise to 1.5 b/d by the start of next year as production is boosted at several key fields.

The onshore Murzuk operation by Spain’s Repsol has progressed ahead of schedule and production could rise from 100,000 b/d to 200,000-240,000 b/d by the middle of next year. Italy’s ENI is also boosting production from the Bouri field and France’s Total is planning to raise output at the Mabruk fields to 40,000 b/d from 11,000 b/d.

The success of these projects has led other international firms to express new interest in Libya. Canadian Occidental has teamed up with the Dublin- based Bula Resources on an exploration and production sharing agreement (EPSA) on Block G in the Ghadames Basin and Block U in the Sirte Basin. Work will begin when the EPSA receives final ratification from the General People’s Committee.

Italy’s Agip is also pressing ahead with the development of Libya’s gas reserves. The company is working on offshore NC41 block and the onshore Wafa field. Agip will invest $3,500 million in the project and expects to produce 10 billion cubic metres a year (bcm/y) from the fields with 8 bcm/y being exported to Italy through a pipeline to Sicily. The project was agreed with Libya in 1996, after both sides signed an addendum to a 1974 EPSA. Agip believes that this protects the project from US sanctions legislation which affects new projects.

Agip remains active in oil field development and is poised to take a stake in block NC 173 in the Gulf of Sirte and NC 174 in the Murzuk Basin. The UK’s LASMO and a Korean consortium led by Korea Petroleum Development Corporation (Pedco) are farming out part of their share in the two blocks. LASMO will remain the operator of both blocks.

Production will also be enhanced at the Waha oil field by a project to supply and install the Faregh production and heating station A. About 11 companies have been invited to bid by mid-November for the $40 million- 50 million project.


The focus of Oman’s upstream activity is the development of the central gas-fields. The main producer, Petroleum Development Oman (PDO), a joint venture of the government, Shell, Total and Partex (Oman) Corporation, is drilling wells and building facilities in the Barik and Saih Rawl fields which will supply the liquefied natural gas plant under construction near Sur.

Three major contracts, for the upstream facilities, interfield pipelines and the pipeline to the plant were awarded late last year and the work is on schedule, PDO says. Gas reserves continue to rise. Non-associated proven reserves now stand at 17 million million cubic feet (tcf) and PDO says it hopes to continue to raise this by 1-1.5 tcf a year.

Oil production has hit record levels this year. Production is expected to average 895,000 barrels a day (b/d) over the full year, up from about 880,000 b/d in 1996. PDO accounts for about about 850,000 b/d of current production but the complex geology of Oman means that further increases are unlikely for several years.

An active exploration programme has enabled PDO to raise its reserves consistently by more than the annual rate of extraction. Reserves are now 5,135 million barrels, the highest ever level. Future developments include the Athel field, which has potential reserves of up to 3,000 million barrels. The first phase of development will use new technologies and cost up to $300 million, PDO says.

Despite the technical difficulties of getting Omani oil out of the ground, a number of independents have recently taken up new concessions. The US’ Occidental signed a seven-year agreement in September, undertaking to spend $45 million on exploration in block 31. Occidental is already Oman’s second largest producer, at about 42,000 b/d. Saudi Arabia’s Nimr Petroleum Company also signed a $50.5 million deal earlier this year. The government says that a further 10 onshore and offshore oil concessions will be available to international companies in the near future.


QATAR has been breaking records this year. Oil production reached a historic high of 571,000 barrels a day (b/d) in May and it is still rising rapidly. Latest estimates for September show a further surge to 670,000 b/d – representing a year-on-year rise of 170,000 b/d – and 300,000 b/d above Qatar’s OPEC quota. Further expansion is on the way as Doha aims for its target capacity of 850,000 b/d by 2001.

The revival of the oil sector began in 1994 with the decision to open the industry to foreign operators. Doha decided that it could benefit from outside financial assistance and technological expertise to boost production above 400,000 b/d and better exploit its reserves.

The foreign firms have made a dramatic impact. In the Idd al-Shargi north dome field, the US’ Occidental Petroleum has raised output to about 100,000 b/d from just under 20,000 b/d, since it signed a development and production sharing agreement (DPSA) with Qatar General Petroleum Corporation (QGPC) in September 1994. Further increases are expected over the next two years as the enhanced oil recovery programme is completed; capacity could reach about 150,000 b/d by 1999.

Denmark’s Maersk Oil & Gas has also been producing about 100,000 b/d from its offshore block 5 concession, known as Al-Shaheen. An estimated $200 million full field development is also under way, which should raise capacity to about 150,000 b/d by late 1998.

Two other firms have begun production from offshore acreage over the past 12 months. The Al-Khaleej field, operated by France’s Elf Aquitaine, was brought on stream in the spring and is producing almost 30,000 b/d. Output is expected to rise to 50,000 b/d over the next three years. The consortium headed by the US’ Arco has been producing up to 32,000 b/d from the Al-Rayyan field from temporary production facilities.

QGPC has also been increasing investment in the onshore Dukhan and offshore Bul Hanine and Maydan al-Mayzan fields. The main focus has been on Dukhan, where project work worth over $500 million is under way. The programme will contribute to a 60,000 b/d increase in production capacity in QGPC fields to 460,000 b/d by 2000.


WITH completion of the Shayba oilfield development in sight, state oil company Saudi Aramco is reviving plans for wider upstream expansion.

However, production is already well in excess of stated supply to the market and considerable unused capacity is also in place. Shayba will add 500,000 barrels a day (b/d) to output next year.

Wellhead oil production, including the share of output from the neutral zone, averaged about 8.6 million b/d in the first seven months of this year. Riyadh’s 50 per cent share of production in the neutral zone has held steady at 250,000-270,000 b/d during the year and is planned to rise to 375,000 b/d by 2000.

Despite the considerable rise in production since 1996 – when output averaged 8.2 million b/d – the Saudis report that supply to market has remained within or only just over the long-standing OPEC quota of 8 million b/d.

Plans for expansion and upgrading focus on increasing production at the huge Ghawar field and raising output of lighter grades. None of the options being considered by Aramco is new; most were shelved for budgetary reasons in the mid-1990s. Improved revenues have enabled Aramco to reconsider them. Oil engineers have also suggested that parts of the 5.3 million b/d Ghawar reservoir are experiencing declining pressure and need to be relieved by new facilities elsewhere in the field.

Industry sources say that the first two schemes to move ahead are likely to be: Haradh-2, a second 300,000-b/d gas-oil separation plant (GOSP) planned for Haradh in the Ghawar field; and revamping of an existing GOSP built at Harmaliyah in the late 1970s, where capacity would be lifted from 60,000-70,000 b/d to 175,000 b/d of Arab Light through debottlenecking. The bidding process for both projects may begin next year.

Aramco is considering adding a new 75,000-b/d GOSP to bolster current capacity of 200,000 b/d at Nuayyim in the Arab Super Light-producing central region. Several international companies have been invited to prequalify for a contract to provide project management services. But industry sources said this month that the scheme, put off several times already, may once again have been postponed.

Future projects could also include: a 100,000-b/d GOSP at Fazran, also in Ghawar; and development of the Midyan gas field in the extreme northwest, which was discovered in the early 1990s but thought too small to develop.


TO most observers, southern Sudan is little more than a wasteland where government troops have battled rebel forces for nearly 30 years.

However, for a handful of intrepid international oil companies, it is an area offering opportunities that even a civil war cannot deter them from pursuing.

In mid-October, selected international contractors submitted bids for the engineering, procurement and construction of facilities to lift production at the Heglig and Unity development areas of the Mughlad basin to 150,000 barrels a day (b/d). The work will also involve laying a 1,610-kilometre pipeline to an oil export terminal to be built at Port Sudan.

The China Petroleum Technology & Development Corporation (CPTDC) and Germany’s Mannesmann are in final negotiations for contracts to supply the line pipe. CPTDC will supply two thirds of the 28-inch-diameter pipe under the contracts, which are estimated to be worth $300 million. The pipe will have a capacity of 250,000 b/d.

The client is the international Sudan Project Consortium (SPC), comprising the China National Petroleum Corporation, Malaysia’s Petronas Carigali Overseas, Arakis Energy Corporation of Canada and the state-owned Sudapet. Malaysia’s OGP Technical Services is the lead project manager with Canada’s MacDonald Engineering. Norway’s Kvaerner John Brown carried out the basic designs for the scheme, and detailed designs will be completed by the contractor. SPC says it aims to award the construction contracts by the end of this year. The work is scheduled to begin in the middle of next year.


The main events in the Syrian oil and gas sector this year have been the signing of three new exploration agreements and the tendering for an associated gas development programme.

Two of the new exploration permits have gone to companies already active in Syria – the Royal Dutch/Shell Group and France’s Elf Aquitaine. MOL of Hungary has taken the third.

Shell, as the operator and majority foreign partner in Al-Furat Petroleum Company, already produces some 380,000 b/d out of Syria’s total production of about 600,000 b/d. Its new permit is the Zenobia block, in the Euphrates Valley, where most of Shell’s existing fields are located. The company will drill four wells in the initial four years of the agreement, and carry out 3-D seismic surveys. Shell is also exploring the Al-Walid block, where it has drilled one well, and is planning a second.

Elf, which produces about 60,000 b/d from the Jafra area next to Al-Furat’s zone of operation, has signed a new agreement to explore the Tishreen block to the north. Its partners are Sumitomo Corporation of Japan and Petronas Carigali Overseas of Malaysia. The agreement runs for seven and a half years, and calls for seven wells to be drilled, along with 3-D seismic surveys.

MOL is committed to drill four wells in its Palmyra East block in the initial 44-month period of its concession agreement.

The resumption of exploration activity has come after a break of several years. Oil companies were attracted by Shell’s success in the mid-1980s, but most of them left after meeting their initial obligations. Dry wells and the lack of incentives from the government to invest more were the factors.

The new agreements reflect a small improvement in the situation, but the contractual conditions in Syria are still regarded as among the worst from the perspective of foreign companies.

For gas, conditions are even worse. Al-Furat now produces about 200 million cubic feet a day (mcf/d) of associated gas, and the Syrian Petroleum Company produces about 300 mcf/d of natural gas from fields in Palmyra and the far northeast. In 1996, the government invited companies to bid for a contract to set up a new associated gas project in the Euphrates Valley, aiming to produce up to 400 mcf/d. Shell bid for this against Conoco and Coastal Corporation, both of the US. Conoco submitted what industry analysts said was the most attractive bid, from the point of view of total production and the level of investment. After lengthy negotiations, Conoco received a letter of intent this summer. However, this has not been translated into a contract, because the government is worried about US sanctions and because Shell has subsequently improved its offer.


INTEREST in Tunisia has risen since new discoveries just across the border in the Algerian fields and oil production may yet rebound. It has been falling over the past few years to around 80,000 barrels a day (b/d) as fields have matured. Improved relations with Libya have also helped, finally opening the way to large-scale exploration of the offshore field shared by the two countries.

The $30 million spending commitment by Saudi Arabia’s Nimr Petroleum Company and Malaysia’s Petronas at the Libyan/Tunisian acreage announced in May is the largest exploration deal signed since the UK’s BG acquired the Miskar field. The 7 November block is estimated to have recoverable reserves of at least 200 million-300 million barrels of oil.

The UK’s LASMO is waiting for approval to farm into the Jenein South block, operated by the US’ Phillips Petroleum, and the US’ Union Texas Petroleum has increased its stake in the Bordj el-Khadra block, which it hopes will connect to an adjacent field in Algeria. A group of mainly Canadian companies has farmed into the South Nefta acreage, operated by Eurogas of the US.

Germany’s Preussag is taking over all the oil interests of BG, which consist of the West Kerkennah block and six small producing fields. Preussag says it wants to increase production to 300,000 tonnes of oil equivalent a year by 1999.

Substantial investment may come from the US’ Arco, which announced it wanted to become Tunisia’s largest foreign oil producer when it bought all the local holdings of France’s Elf Aquitaine in September. The deal included the offshore Ashtart field, which produces 19,000 b/d and is to undergo further development.

BG completed its first full year of gas production in June, having solved a technical problem which had caused a suspension of several months. It sells 4.5 million cubic metres of gas a day to the state power company.

A smaller gas project is going ahead in El-Franig and Baguel, where operator CMS Nomeco International of the US is building a processing facility for 15 million cubic feet of gas and 3,000 b/d of condensate.