Producers untangling Angola's complex deepwater geology

Twelve billion bbl of oil have been discovered to date in Angola, since the first commercial discovery in 1955. The current reserves estimate, according to state owned oil company Sonangol, is nine billion bbl. But, the rate of discoveries in the last 44 years has been uneven. The 1980s witnessed discoveries in rapid succession, culminating in a total of two billion bbl, or 17% of the total discovered to date (TDTD). But even this achievement pales in significance to the growth in the last five


Turbidite sands most productive interval

Toyin Akinosho
Contributor - Lagos
Twelve billion bbl of oil have been discovered to date in Angola, since the first commercial discovery in 1955. The current reserves estimate, according to state owned oil company Sonangol, is nine billion bbl. But, the rate of discoveries in the last 44 years has been uneven. The 1980s witnessed discoveries in rapid succession, culminating in a total of two billion bbl, or 17% of the total discovered to date (TDTD). But even this achievement pales in significance to the growth in the last five years. Since 1995, five billion bbl, or 41% of TDTD, have been discovered.

Officials at Sonangol insist that this is only a small portion of Angola's total hydrocarbon potential. The Namibe, one of Angola's three major coastal sedimentary basins, is currently unexplored. The Lower Congo and the Kwanza basins have been the sites of exploration, discovery, and production.


A composite cross section of the post-salt sequences offshore Cabinda.

Economic environment

The economic and social implications of this all-time boost in reserves is worth reviewing. Angola currently is the second largest oil producer in sub-Sahara Africa. Angola's population, 11.5 million, is spread on a relatively large areal size of 486,000 sq km. The country has a coastal length of 1,600 km, off which much of the oil reserves are produced.

Oil accounts for 90% of total exports, more than 80% of government revenues, and contributed 42% of GDP in 1998. Nigeria, the larger oil economy, located 1,200 km to the northwest, sports remarkably similar figures for government revenue and percentage of total exports.

But with nine billion bbl of oil in reserves, Angola's per-capita oil wealth is 782 bbl, whereas giant Nigeria, with 20 billion bbl and a population of 100 million, has a per-capita oil wealth of 200 bbl. Gabon, with a population of 1.19 million and 2.5 billion bbl in reserves, has a per-capita oil wealth of 2,100 barrels. Very little is known about Nigeria's solid mineral resource base, whereas in Angola, a valuable resource such as diamonds, can help curtail overdependence on oil.

Angola has endured a civil war for all of its 24 years as an independent country, and even so actively engages in the armed politics of its neighborhood. But, the oil industry, located mostly in offshore Cabinda, has been shielded from the ravages of the battlefront.

Angolan events

The historic boost in oil reserves in Angola since 1995 is in sync with the period of deep water activity in the country. Current opinion in the oil patch - that West Africa's deepwater fairway is the world's most exciting exploration theater - can be entirely correlated with events off Angola. In the first 10 months of 1998, deep water discoveries in Africa totaled 13, nine of which were in Angola, three in Nigeria, and one in Congo.

The current phase of the race for the deepwater in Africa started tentatively at the beginning of the 1990s. In Nigeria and Angola, deepwater acreage was parceled out by 1993. Shell took an early lead in 1995, drilling two wells on the then-promising Bengo structure, of which the first well tested 1,780 b/d of oil. The company also drilled another wildcat Cunene, elsewhere in the same Block 16. Elf reported gas and condensate in Magarida-1.

Nigeria ended 1995 with the drilling of Allied/BP-Statoil well Oyo-1, which has since proved to be a marginal oil find. But the same year also witnessed the testing of Shell's most successful effort in deepwater West Africa - the Bonga structure. The field, at 500 million bbl, is being primed to go onstream by 2001.

Then Angola raced ahead. In April 1996, Elf's Girassol-1, located in 1,365 meters of water in Block 17, tested 2,800 b/d of oil on a reduced choke. Today, with two more wells on the structure, the recoverable reserves are reportedly in excess of 900 million bbl. Other large finds came, as if on cue. In 1997, Dalia and Rosa, located 8 km to the southeast and 19 km northwest of Girassol, respectively, were discovered. The Lirio discovery, located 32 km northwest of Girassol, was announced in late 1998.

Chevron and Exxon have also been reporting discovery after discovery. In Chevron's Block 14, Kuito initially tested an aggregate of 7,500 b/d of oil in wildcat D-14-2 in April 1997; Landana, tested a cumulative rate of 7,480 b/d of oil in three intervals in wildcat D-14-6 in December 1997; and Benguela flowed 20,000 b/d of oil from three intervals in wildcat D-14-9 in July 1998.

In 1998, due south in Block 15, Exxon reported testing 15,900 b/d of oil from three intervals in Hungo, 10,000 b/d of oil from Kissanje, and 6,800 b/d of oil for Marimba. Each of these were reported to hold possibly 500 million bbl estimated recoverable reserves. A fourth find, Dikanza may not rank as particularly large in itself, but it contributes to substantial reserves in the block.

Of the four major operators doing active work in deepwater Angola, Shell has had the worst luck. Between September and October 1998, the company plugged and abandoned two wells: Cubango-1 and Chiluango-1 on locations 85 km apart in the same Block 16, where it plugged and abandoned Cunene in 1995. Shell had been disappointed with Bengo-2, the appraisal well to the promising discovery Bengo-1, which results had led to plans for a fast track development.

Angola's deepwater geology

The geology of the Angolan deepwater fairway evolved as part of the geology of the entire West African segment of the south Atlantic. Six basins line the coast of West Africa, all of them part of the Passive Margin and Delta Sag Basin families, which are the two most productive of the five major families of sedimentary basins in Africa.

The six basins are part of a large linear trough, which has been subsiding, probably since late Jurassic time. It was then that the super-continent Gondwanaland divided into West Africa and South America, forming the Atlantic Ocean between them.

The Gondwanaland breakup was probably initiated in the Gulf of Guinea area, where a thick and extensive miogeoclinal wedge of sediment accumulated along the continental margin of West Africa. The basins include:

  • Abidjan, which straddles Côte d'Ivoire and the Tano and meta sub-basins in Ghana
  • Offshore Benin, which is structurally defined by the Romanche Fracture Zone in the west and the Okitipupa High (in Nigeria) in the East with the western flank extending to Togo
  • Niger Delta, which is located between Okitipupa High in
the west and the Cameroon

volcanics in the east and including the Rio-Del-Ray-Cameroon-Fernando Po Basin

  • Gabon Coastal, which extends from the southern part of the Cameroons, through Equatorial Guinea to Gabon, where it is bounded to the south by the Gabon Fracture Zone
  • Lower Congo, which extends from Congo to Angola and is bounded to the north by the Gabon Fracture Zone
  • Kwanza Basin, which runs right on the edge of Angola, from North to South
  • Congo Fan, which lies parallel, on the seaward side of the Lower Congo Basin. It is the ultra-deepwater portion of the Lower Congo Basin, and comes across as if its created by dumping of sediments from the Congo River, which cuts perpendicular to the trend of the Lower Congo Basin. The Congo Fan, essentially a Tertiary development, is younger than the Gabon Coastal, Lower Congo, and Kwanza Basins, all of which are Cretaceous in age.
The Gabon Coastal, Lower Congo, and Kwanza are altogether regarded as sub-basins of the Aptian Salt Basin, or more simply "Salt Basin", as each of them share common stratigraphic characteristics. The Salt Basin was initiated with the Late Jurassic to Early Cretaceous rifting of the super-continent Gondwanaland.


Evolution of the Kwanza Basin offshore Angola.

Neocomian to Lower Aptian synrift fluvial clastics and lacustrine shales were deposited during the initial stages of separation of Africa and South America. The early post rift section is dominated by thick marine evaporites. Carbonates were deposited during the Albian.

Sand deposition

With continued seafloor spreading during the tertiary, a thick sequence of shales and turbidite sands were deposited. Since the Middle Oligocene, three agents have promoted deepwater sand deposition in the Lower Congo Basin.

  1. Uplift of the West African coast has steepened the continental margin and exposed crystalline basement rocks at the basin edge and in adjacent fluvial catchments.
  2. Northward drift of Africa has caused the basin hinterland to pass from a climatic zone to a more humid one, promoting erosion and delivery of sediment to the basin.
  3. Periodic glaciation arising from the evolution of the Antarctic ice cap, has significantly lowered and fluctuated sea level respectively, facilitating clastic transport into the deepest part of the basin.
The thickness of the post-rift, Aptian salts (those formed in situ) varies from zero to several km in the mid to lower slope (deepwater) of the Lower Congo and Kwanza Basins, where they influence the structural styles of the overlying structures. This variable thickness creates strong lateral velocity gradients and imaging problems.

Comprehensive mapping techniques have revealed a set of major basement faults, parallel to the basin margin and generally stepping down to the west (seaward). The major development on these faults occurred during the rifting stage. The salts mark the boundaries between zones of different structural style. The movement of sediment sheath over basement generates growth synclines, whose architecture is controlled by the rate of sediment aggradation and the rate of downslope sliding.

Field similarities

Seismic profiles in the deepwater Lower Congo and Kwanza shows that the structures in the mid to lower slope are dominantly created by compressional folding, with subordinate salt-withdrawal and diapirism Oligocene and Miocene deepwater sands of the deepwater turbidite sands (Malembo Formation) currently are the main prospective intervals in the deepwater wells of the Lower Congo Basin (Congo Fan). This is where Girassol, Dalia, Rosa, Hungo, Belize, Landana, and the rest of the big discoveries are located.

In conferences from Lagos in Nigeria to Rio in Brazil, Exxon has compared the deepwater reservoir sandstones in the Lower Congo Basin with those in the North Sea and Gulf of Mexico. They suggest that they are very similar and recommend these two mature basins as capable of providing useful insights into the likely nature and performance of the Lower Congo Basin deepwater reservoirs.

Three-dimensional seismic data from the Lower Congo Basin presented at the AAPG conference in Rio de Janeiro indicated a profusion of bright, high-amplitude reflections in the late Oligocene and Miocene succession. These are interpreted to be deepwater reservoirs.

Observable signatures on 3D seismic profiles include uniform, concordant, and internally continuous reflections - frequently interpreted as overbank deposits. Conformable seismic reflections with constructive geometry, obviously different from those suspected overbank deposits, are believed to be leveed channels, resulting from the build-up of the levee crest above local topography. Linear, frequently erosive features showcasing internally discontinuous high amplitude seismic characters.


Development activities are underway on a number of large fields off West Africa:

  • Kuito: Chevron is on course for the first oil in deepwater Angola. The company's established infrastructure in the shallow offshore, helped in the fast-track development of the Kuito field, which is just next door to the company's well developed Gulf Cabinda areas A, B, and C. The company plans to start production in early 2000, less than three years after discovery. Initial output is expected at 75,000 b/d of oil, and will peak at 100,000 b/d by 2002. Reserves are estimated to be between 500 million bbl and 1 billion bbl. A consortium involving ASEAN Brown Boveri, Coflexip Stena Offshore, and headed by Single Buoy Mooring Production Contractors, has been awarded contracts totaling $400 million for the initial phase of the field development. The consortium will provide a floating production and storage vessel (FPSO), export buoy, subsea wellheads, and piping. This system will be capable of handling 100,000 b/d of oil with facilities for water and gas injection. Kuito will also be a zero-flare field. The associated gas will be reinjected back to the reservoir. One plus for this forthcoming field is that, in the event of sufficient reserve size, the ultimate plateau rate of 200,000 b/d of oil could be attained in a second phase to cost an estimated $2 billion.
  • Girassol: Elf faces a more daunting, technical, and financial challenge with the Girassol Field, lying in 1,370 meters of water. First oil is slated for year-end 2000, building to a peak of 200,000 b/d. Elf said that Girassol development will involve the largest infrastructure for such depths, as well as innovative technology. The bill is estimated at $2.5 billion. Elf recently awarded $1 billion worth of contracts for the field development. Plans include 40 subsea wells (23 will be producing, 14 will be water injection, and three will be gas injection wells). Production per well will range as high as 40,000 b/d of oil. Girassol field is 18 km long and 10 km wide, with a substructure of meandering sand complexes with overlapping channels. The high reservoir quality allows for efficient drainage with the drilling of few wells. Girassol marks the first time this French major has taken such a fast track approach to development. Facilities will be constructed simultaneously with early field development. An early screening phase has led to the selection of a subsea completion system and FPSO barge. The wells will be drilled from one semisubmersible rig and one dynamically positioned drillship. Together they will cost $600 million. Nearby, a development concept for the Dalia prospect is under study. One appraisal well has been drilled. An investment decisions will come later in the year.
  • Exxon's projects: In the wake of her deepwater Angolan discoveries, Exxon has formed a new company Exxon Upstream Development Company, with which she will make further appraisal work and development evaluation.

Future plans

These discoveries, and their development in the space of a few years, mark only the beginning of activity in deepwater Angola. Less than 40 wells have been drilled in deepwater Angola as of the end of October 1998. Angola plans to increase production to 1 million b/d by 2000, an expansion that depends on reserves being proved up in deepwater. Yet even today, the petroleum geology offshore is poorly understood and studies are continuing.

As the technical program gets underway in the workstation rooms of the majors, what we hear most are the bidding processes and the concession awards. The Angolan government reportedly recently awarded leases in the farther deepwater, west and southwest of the Blocks 14, 15, and 17, where the giant discoveries have been made. The prospectivity of these Blocks 31, 32, 33, and 34 rests on the supposition that the Congo Fan is much better developed slopewards.

The interesting paradox of Angolan history is that its oil industry is thriving, when the civil war rages most. Officials talk about "political and economic stability, along with the peace process," even as war limits life only to Luanda and offshore Cabinda and United Nations planes are downed by Unita rebel forces. But, the investment continues, and with it, the hope of becoming Africa's major oil producer.

Copyright 1999 Oil & Gas Journal. All Rights Reserved.

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