Africa

Optimism saturates the continent

Exploratory success is rampant, particularly in deepwater areas off West Africa. Natural gas is driving heightened activity in Egypt, while oil development progresses in Algeria, Sudan and Chad

All countries by Melissa A. Manning, Global P.R. Manager, IHS Energy Group, Houston; and Jean-Marie Conne, Andrew Hayman, Michel Marchat and Dmitri Massaras, Editors, Saharan and Sub-Saharan Africa, Global E&P Service, IHS Energy Group, Geneva

Egypt. The 2001 Bidding Round closed last February, with 32 blocks available offshore and onshore. The country hopes to award some of these blocks to companies during 2002.

There were 132 development wells drilled in 2001 – 95 onshore and 37 offshore. Khalda was the most active onshore operator, with 25 wells drilled in 11 fields. Offshore Egypt, Burullus Gas Co. began development of Saffron and Scarab fields. Rashpetco completed two gas wells in Rosetta 3 field (Nile Delta). In the Gulf of Suez, Ashpetco, Geiso, Gupco, Petrobel, Rudoco and Suco drilled wells.

Centurion Energy International made three gas / condensate discoveries (El Manzala concession). These included El Wastani East 1 (June 2001, 10,170 ft, reserves of 3.6 Bcfg and 90,000 bbl of condensate); Gelgel 1 (August 2001, 4,101 ft, 15 Bcfg proven and 30 Bcfg probable) and Sherbean 1 (November 2001, 20 MMcfgd).

Ocean Energy hit an oil find (8,000 bopd and 1.4 MMcfgd) in Zeit East A-21, adding another 40 million to 80 million bbl of oil. Last year, dry holes were drilled by BP (Aztec 1, West Mediterranean deepwater Block B), IPR-Transoil Corp. (three dry holes in the North Bahariya Block) and Shell (wildcat BFD 1, Abu El Gharadiq Block). Aztec 1 was particularly disappointing, given the success of BP’s first well, Ruby, which was suspended last March as a gas discovery with possible in-place reserves of nearly 3 Tcf.

Burullus Gas Co. struck three gas finds (Sapphire 1, 2 and 3) in its West Delta Deep Marine (WDDM) Block. Sapphire 3 found gas in two formations. Reports suggest that a 1,887-ft gas column has been established, making it one of the largest gas columns ever encountered in Egypt.

Dikirnis 1, the second of Merlon Petroleum’s three back-to-back exploration wells on the El Mansoura permit, began drilling in June 2002. The final well will be Mit Hadid 1. Last January, Merlon completed El Mansoura 3 (Jb 64-4) as a gas find in the block’s western portion. Preliminary reserves are between 25 and 50 Bcfg.

During the past year, Eshpetco drilled five wells (three oil wells, two dry holes) in its West Esh El Mellaha (WEEM) development lease, yielding 33 million bbl of provisional oil reserves in the Nubia formation.

Egyptian production was 616,000 bopd, 82,400 bcpd and 2.8 Bcfgd. Officials said that during the period from July 1 to Nov. 15, 2001, 15 new discoveries were struck, adding 178 million bbl of crude and condensate, and more than 1.5 Tcf of gas. At the end of 2001, Egypt’s reserves stood at 3.7 billion bbl of oil and 54 Tcf of gas.

Nigeria. The country has a goal of expanding oil reserves to 30 billion bbl from 20 billion bbl by 2005, and then to 40 billion bbl by 2010. Given that Shell has already partially exploited the now mature, onshore Niger Delta (15 billion bbl recovered since 1958, with 15 billion bbl remaining), most growth must come from very large fields in deep and ultra-deep waters. Fortunately, deepwater drilling continues at a furious rate, with remarkable successes.

In Block OML 118 of the southwestern Niger Delta, Bonga is the first deepwater field that will come onstream – at the end of 2003. Shell expects to pump more than 600 million bbl of oil from Bonga. However, deeper field levels are yet to be tested, so recovery could jump to 1 billion bbl.

Another giant Shell field, Bonga Southwest, will be exploited by an exact replica of the Bonga FPSO operation (to reduce costs and shorten time to first oil). Given other interesting prospects, OML 118 is conservatively reckoned to have a 2-billion-bbl-plus potential for recoverable oil. Shell is also developing EA field in OML 79.

Other operators are enjoying similar Niger Delta successes. TotalFinaElf will develop Akpo field (OPL 246) – another giant. One of TFE’s recent successful wildcats is pre-appraised at 270 million bbl of oil. Given its proximity to the Ukot 1 success, a cluster-type development is under consideration. TFE also began development drilling at Amenam-Kpono field in May.

ChevronTexaco holds major delta acreage successes at Agbami field (1 billion boe in OPL 216), and the successfully appraised Aparo 1 deepwater discovery (OPL 213). Agbami will be developed in spite of costly, frustrating delays in approvals.

This year, Transocean’s Sedco Energy semisubmersible tested ChevronTexaco’s Aparo 2 (11,575-ft planned TD) location and then moved onto OPL 218, to spud an appraisal to Statoil’s Nnwa 1 discovery of 1999. With reserves speculated to be 75 million bbl of oil and 1.5 Tcf of gas, Nnwa looks like a solid development bet.

ExxonMobil is moving ahead with development of 500-million-bbl-plus Erha field (OPL 209), which should produce about 200,000 bpd. Agip has put Okono field (OML 119) onstream, and is now working on Okpoho field in the same block. Amni has brought in a Chinese rig to help further develop Ima Field (OML 112).

Floating plants and the prospect of 150 Tcf to 300 Tcf of gas will make LNG more attractive. Shell and partners have shown the way, with a successful LNG plant at Bonny Island, which is being expanded to five trains. Other majors (ExxonMobil, Phillips / Agip and Statoil) are vying to set up new plants to export LNG to the U.S. and Europe, in pursuit of gas resource "monetization."

The island state of Sao Tome and Principe hopes to join in Nigeria’s successes, thanks to the newly created Joint Development Zone (JDZ) between the two countries. A JDZ licensing round will be launched later this year, and a rush of applicants is expected. An all-Nigerian licensing round will offer other, highly prospective deepwater acreage in 2003, plus shelf and onshore blocks. A marginal fields round is directed toward Nigerian companies.

Nigerian oil production remained virtually unchanged, at 2.008 million bpd. Official reserve reports said that Nigeria had at least 30 billion bbl of oil and 159 Tcf of gas. These are conservative figures.

Algeria. No timetable has been announced for adoption and implementation of the proposed new hydrocarbons law. The proposed law is a radical departure from Algeria’s previous approach to hydrocarbon licensing. The fiscal regime would no longer be based on production sharing, but instead on a system using royalty, petroleum revenue tax and corporate income tax.

In July, state firm Sonatrach and the Energy Ministry signed PSAs for seven of 10 packages. These packages comprise 13 blocks in the Third Licensing Round for exploration. During 2001, there were 337,353 sq mi under license in Algeria. Sonatrach was the sole offshore license-holder.

Last year, 56 development wells were drilled. Sonatrach (22 wells) was the most active operator, followed by BHP with 10 and Anadarko with seven. BHP continued drilling at the Ohanet Development Project (set to produce 700 MMcfgd) and at the Rhourde Oued Djemaa field complex (six fields to produce 80,000 bopd). Both projects should go onstream in 2003.

BP and Sonatrach began joint development of the In Salah Gas Project in southern Algeria. First output is expected in 2004. Three fields – Krechba, Reg and Teg – contain about 7 Tcf of gas. Anadarko continued development drilling in Hassie Berkine oil field. First production occurred last December. Average daily field output increased to 169,000 bopd from 55,000 bopd, following completion of additional central processing capacity.

For 2001, Algeria’s crude production averaged 775,000 bpd, versus an OPEC quota of 773,000 bpd. Current condensate output (which is exempt from OPEC quotas) is estimated at 400,000 bpd. Average natural gas production is 7.4 Bcfd. Algerian reserves are estimated to be 17 billion bbl of oil and 175 Tcf of natural gas.

The Energy Ministry and Sonatrach opened a bidding round (bids due on October 10) for the Gassi Touil Integrated Gas Project in the Berkine basin. This six-field, 9-Tcf project is the largest of its kind in Algeria’s history, and will require exploration, development, pipeline transport, liquefaction and marketing.

Algeria and Nigeria met recently to formulate a bilateral, economic cooperation agreement that includes the Trans-Saharan Gas Pipeline (TSGP) project. Nigeria plans to export gas via TSGP to Europe. The cooperation agreement supports use of Nigeria’s huge gas reserves for economic development, and to stop flaring that otherwise contributes to air pollution.

Angola. TotalFinaElf brought Girassol field into production last December, five years and seven months after its discovery. By January 26, production had jumped to 186,000 bopd from seven wells. Peak output for Girassol’s first phase was set at 200,000 bopd. Ultimately, the Phase One plan will tap 725 million bbl of oil reserves.

ExxonMobil plugged and abandoned wildcat Semba 1 as an oil discovery on Block 24. Two reservoirs were flowed at a combined rate of more than 3,000 bopd on test. Although the discovery was rated as sub-commercial, this was the first time that a working petroleum system was identified in the Benguela sub-basin.

BP plugged and abandoned wildcat Jupiter 1 as dry in Block 31. This was the first test in one of four ultra-deepwater blocks under license in the Congo Fan (Block 31, BP; Block 32 TotalFinaElf; Block 33, ExxonMobil; Block 34, Sonangol P&P). The tertiary objectives were encountered. However, they were found to be water-bearing.

ChevronTexaco made a new oil discovery in deepwater Block 14 with Tombua 1x. The well tested an aggregate of more than 10,000 bopd from two unspecified zones. This was the seventh oil find made by the company in Block 14 since 1997 (Kuito).

Last August, ExxonMobil launched the $3.2-billion Kizomba "A" field development project. Kizomba "A" will develop the Hungo and Chocalho oil discoveries in deepwater Block 15.

During 2001, Angola’s crude oil output was maintained at about 755,000 bopd, thanks to new contributions from several development projects. These include Nemba field; Kuito field (Phase 1 became operational October 11); Girassol field (produced first oil December 4); and Nunce Sul field.

A renewal of significant development drilling in Sudan contributed to a doubling of the number of wells drilled there in 2001. (Photo courtesy of Talisman Energy)

Sudan. At the end of 2001, rights holdings in Sudan covered 192,177 sq mi, including 8,996 sq mi offshore. These figures are 41% and 302% higher, respectively, than the same categories a year earlier. One new contract and one TEA were made during the last year.

In October, Algeria’s Sonatrach signed a four-month TEA with the government for Suakin Gas field in Block 15, offshore in the Red Sea. The move was made with future exploration in mind. Sonatrach will evaluate 3,728 mi of 2-D seismic and petrophysical data from 12 wells, in and around Block 15.

Marathon expects to dispose of its 32.5% interest in TotalFinaElf-operated Central Block B, by either sale or farm-out. Two Sudanese blocks remain under "force majeure." These tracts are TotalFinaElf’s Permit B (partially in rebel-controlled southeastern Sudan) and Lundin Petroleum’s Hailab Block (along the Red Sea Coast in territory disputed with Egypt).

Last year, 109 mi of 2-D seismic and 17 sq mi of 3-D seismic were acquired onshore Sudan, versus 3,099 mi of 2-D seismic recorded in 2000.

Greater Nile Petroleum Operating Co. (GNPOC) and Lundin Petroleum were the only operators active in the Muglad basin. Lundin suspended Block 5a operations last January because of safety considerations, due to civil unrest in southwestern Sudan. There was no offshore activity during 2001.

Sudanese exploratory drilling totaled 25 wells, compared to 22 wells during 2000. Most wells were suspended after testing, although five were plugged and abandoned as dry holes. GNPOC was the most active operator, drilling 20 wildcats and other exploratory wells. Development drilling tallied 23 wells onshore for 130,584 ft, versus just one well in 2000. No development drilling occurred offshore.

Average output from all fields was 223,000 bopd, up from 145,807 bopd a year earlier. This year, Sudan will increase output to 290,000 bopd via development and commissioning of new fields. Sudan also plans to increase transportation capacity.

Libya. Petroleum legislation has been under review since 1996, but a new Petroleum Law has not yet been ratified. Originally expected to revamp 1998’s EPSA III contract, the law is in a much-reduced form, dealing mainly with the downstream sector.

Last January, the U.S. State Department authorized the Oasis Group (Amerada Hess, Marathon and Conoco) and Occidental Petroleum to renegotiate their long-dormant Libyan contracts that have been preserved under "Standstill Agreements" with Tripoli. However, this action did not authorize a return to Libya. Libya warned these companies last September that they had one year to return or risk losing their concessions.

NOC has received proposals from various oil companies for 23 packages or work programs covering 59 of 125 blocks in the current bidding round. NOC indicated that the offers include commitments to acquire 30,450 mi of 2-D seismic, 1,245 sq km of 3-D seismic, and drill 81 exploration / appraisal wells. All of this could amount to a $770-million investment. Negotiations continue – NOC plans to award some of the contracts by late 2002.

As 2001 ended, acreage held under concessions or E&P sharing agreements (EPSAs) totaled 147,381 sq mi. Holdings included 141,217 sq mi onshore and 6,164 sq mi offshore, on the continental shelf and in deep water.

Libyan exploration activity remained stable. Eight operators drilled 22 wells, all onshore. Eight of these wells were dry holes. Repsol (nine wells) was the most active operator. In late August 2001, Veba tested 854 bopd and 3.4 MMcfgd in shallower pool wildcat F-6-72, on Block 72-North in Barrut oil field, Sirte basin.

As regards the $5.5-billion, West Libya Gas Development Project (WLGDP), Malta has approved Snam’s construction of the underwater portion of a gas-export pipeline from Libya to Sicily. The project will cross Malta’s continental shelf. It will have a capacity of 800 MM to 900 MMcfgd and be completed by 2004. The pipeline will be fed by two large gas fields. One is Al Wafaa, onshore near the Algerian border. The other is C/NC41, a geologic structure offshore, south of El Bouri oil and gas field. The contract also calls for delivery of 70 Bcfg/year to Libya’s domestic market.

Development drilling tallied 77 wells last year, up 42.6%. The most active operator was Agoco (17 wells). Veba Oil followed with 10 wells, and Sirte Oil Co. drilled eight. Most of these wells were completed as producers. Average Libyan oil production was 1.408 million bpd. Estimated average gas output was 1.5 Bcfd. NOC has not yet announced any revisions to reserve figures. The estimated, remaining, undiscovered oil-in-place reserves potential is 107 billion boe. Proven producible reserves are 30 billion bbl of oil.

Chad. During fourth-quarter 2001, Cliveden Petroleum Co. Ltd. continued acquisition of 1,367 mi of 2-D seismic in Area 1 of Permit ‘H’ (168,725 sq mi). The company has the option to accelerate exploratory drilling before March 2003, if conditions warrant. Cliveden also has the option, but not the obligation, to acquire 3-D seismic data.

Only one exploratory well was drilled during 2001, for 6,041 ft. On Jan. 4, 2002, Esso suspended the Nya 1 exploration well as an oil discovery in the South Chari Block, Chad basin.

Esso continued construction activity on the Chad-Cameroon Development Project (CCDP). CCDP is developing and linking, via pipelines, several oil fields in the Doba basin of southern Chad, to an offshore, oil-loading port at Kribi, Cameroon. Other partners in the consortium are Petronas (35%) and Chevron (25%). Two, specially made drilling rigs arrived for field trials – drilling of development wells began in first-half 2002.

Congo (Brazzaville). Thanks to several new developments, Congo is now the fourth-largest oil producer in Sub-Saharan Africa. Crude oil production ran 275,000 bpd in 2001, down slightly from 280,500 bpd produced in 2000. Output is expected to remain roughly at the same level during the next few years. Natural gas production statistics are difficult to verify, but output is believed to be near 365 MMcfd.

On Sept. 10, 2001, the governments of Congo and Angola signed a protocol agreement establishing the basis for joint exploration and development of a limited sector along their common maritime border. The agreement specifies that Angola and Congo will provide for unitization of two prospects, Nkouimbi in the A-IMI sector of TotalFinaElf’s Haute Mer permit in Congo and 14k in ChevronTexaco’s Block 14 PSA in Angola. A 696-sq-km, joint exploration / development zone has been defined.

Once both countries ratify a final agreement, TotalFinaElf, ChevronTexaco and partners in the two permits will be able to drill the promising Nkouimbi prospect. Partner Energy Africa anticipates that a well will be drilled by the end of 2002. Early indications suggest that ChevronTexaco will be selected as operator of the joint PSA.

Cameroon. The first pipe for the underground, crude oil transportation pipeline was installed in November 2001. Work started on two fronts simultaneously along the right-of-way. By the end of April 2002, 25% (263 km) of the pipeline was completed at a rate of 2 km/day. Building also began on the marine terminal, which will be offshore Kribi, Cameroon.

ABN Amro & Credit Agricole Indosuez, along with 16 other banks, approved a $600-million loan to help finance part of the construction of the $3.7-billion oil field development and oil export pipeline (665 mi) in the Esso-operated CCDP project.

Gabon. Exploration permits were won by Amerada Hess, TotalFinaElf and Shell. In addition, Vaalco was granted an exploitation permit. Pan-Ocean Energy won a production concession (Remboue), and Sasol was granted a TEA (Phe’nix).

Discoveries were made by Shell onshore (Toucan 2) and Pioneer offshore (Olowi Marin 1, 26 ft of net oil pay), plus a successful two-well appraisal program on Vaalco’s Etame Marine field. Toucan field could potentially produce between 15,000 and 20,000 bopd. Ministerial sources confirmed that Shell discovered recoverable reserves between 20 million and 50 million bbl of oil.

Oil production trended downward, averaging 302,000 bopd, or 9% less than 2000’s level. Brought onstream in February 2001, Atora field produced nearly 20,000 bopd to become TotalFinaElf’s largest onshore producer. In December 2001, output from Rabi-Kounga was roughly 62,000 bopd.

Alba gas / condensate field initiated Equatorial Guinea’s hydrocarbon production in 1984. Over the last year, former operator CMS Energy and current operator Marathon Oil have increased proven and probable reserves at Alba to 4.6 Tcf of gas and 300 million bbl of condensate. (Photo courtesy of Equatorial Guinea Ministry of Mines and Energy)

Equatorial Guinea. Last year was marked by CMS Energy’s gas / condensate discovery in the Niger Delta, and two, new oil finds in the Rio Muni basin by Triton / Amerada Hess. Additionally, last January 3, Marathon acquired all of CMS’ assets in Equatorial Guinea for $993 million in cash. The national oil company, GEPetrol, also was created.

The Block N PSA, on the Corisco Bay shelf in the Rio Muni basin, was awarded to a Petronas-led group. Geophysical activity increased significantly in the country during 2001, with new 3-D and 2-D seismic recorded offshore.

Exploration drilling featured significantly increased activity. CMS suspended Estrella 1 as a gas / condensate find in the Niger Delta, Alba Block. The well is 8 mi north of Alba field in 200 ft of water. Estrella 1 tested 47.3 MMcfgd and 6,780 bcpd. In the same block, CMS drilled two wells that increased proven and probable reserves from Alba field to 4.6 Tcf of gas and 300 million bbl of liquid hydrocarbons.

Triton Energy’s (now Amerada Hess) Oveng 1 wildcat encountered 51 m of net, oil-bearing pay from two zones. The well is 3 mi northeast of the Okume 1 oil find (G-5) that struck 174 ft of net, oil-bearing pay in one pool. Both structures were appraised extensively during second-half 2001.

Including Ceiba field, area oil reserves could exceed 600 million bbl. Once all the wells have been drilled and completed, Amerada Hess expects to produce 80,000 to 100,000 bopd from 10 wells. The Sendje Berge FPSO was replaced in January 2002 by the new FPSO, Sendje Ceiba. The new unit can handle 160,000 barrels of fluids per day and inject 135,000 bwd.

The country’s average oil output rose to 193,242 bpd during 2001, due to increased contributions from Exxon Mobil’s Zafiro field (after installation of the Jade platform) and Ceiba field.

Tunisia. At the end of 2001, 54,868 sq mi were under license, including 9,787 sq mi on the shelf and 3,485 sq mi in deep water. In addition, 1,180 sq mi were held on the shelf in the Libya / Tunisia Joint Exploration Zone.

Last February, state company ETAP issued a list of 20 blocks available for direct negotiations. Over the last year, licenses were awarded to Anschutz, Preussag and ETAP. In addition, ETAP acquired 75.5 % of the Mahares concession (Agip retains 24.5%).

Other permits were awarded to Hydrocarbures Tunisie Corp. (HTC) and Tunisian Offshore & Onshore Petroleum and Industrial Contractor, and Nuevo Energy. HTC also acquired 13.62% of the Ezzaouia onshore concession, operated by Maretap, a joint venture between ETAP and Ecumed Petroleum Zarzis Ltd. Last December, Pioneer Natural Resources, Nuevo Energy and Anadarko Petroleum (operator) jointly acquired Coho’s 22.92% interest in the Anaguid permit.

In 2001, 2,726 mi of 2-D and 9 sq mi of 3-D seismic were acquired onshore. There were also 792 mi of 2-D and 478 sq mi of 3-D seismic shot offshore. These figures are considerably higher than year-earlier levels.

Seven onshore exploratory wells were drilled, compared with eight wells in 2000. Four of these were successful, including Agip’s Hammouda Nord 1 (oil and gas); Athanor’s Sabria Nord 3H (onshore, El Djerid basin); Preussag’s Guebiba 3 (oil discovery); and Sitep’s El Borma SE 1 (oil in El Borma field). No exploratory wells were drilled offshore in 2001.

Seven development wells were drilled onshore by Agip, Ecumed and Sitep, and offshore by Coparex and Preussag. A number of good development projects are in progress that should offset the small, but regular decline in production.

In 2001, Tunisian oil production decreased 10.4%, to 69,577 bopd. About 65% of output comes from onshore fields. Marketed gas output averaged about 200 MMcfd – 30 MMcfd onshore from El Borma field, and 170 MMcfd offshore from Miskar Field.

In early 2002, crude reserves were estimated at 526.5 million bbl, of which two-thirds were onshore. Condensate accounted for 72.6 million bbl of reserves. Gas reserves tallied 2.7 Tcf.

Democratic Republic of Congo (DRC). Last year, ChevronTexaco’s Misato 3d exploration well tapped a marginal oil discovery on the shelf. This was the first wildcat drilled in the DRC since October 1998. It was completed as an oil well and brought into production in March 2001. However, it has since been shut-in.

Onshore, Perenco successfully drilled development well KK-44 to a 5,653-ft TD in Kinkasi field during October. It was completed as an oil producer, testing 1,800 bopd before stabilizing at 600 bopd. It was put onstream in November. On the shelf, ChevronTexaco drilled four wells in the GCO South, Libwa and Lukami fields during 2001. DRC production averaged 24,500 bopd for the year.