Côte d'Ivoire's offshore holdings. Ocean Energy made a deepwater push by drilling the East Grand Lahou prospect, but the results were disappointingly dry.
Of the six sedimentary basins that lie astride the West Coast of Africa, the Abidjan Margin has, until recently, been one of the least studied. The Aptian salt basins onshore and offshore Angola, The Congo, Gabon, Cameroon, the Niger Delta Basin, Equatorial Guinea, and Cameroon have been well studied and evaluated. But far less is known of the Benin Basin (Nigeria and Benin Republic); Cameroon's Rio del Ray, often vaguely described as a finger of the Niger Delta Basin; Ghana's Accra-Keta Basin; Togo's Lome Basin; and the Abidjan Margin and San Pedro Basin off Côte d'Ivoire.
Oil operating companies tend to show little intellectual interest in a sedimentary basin once it is perceived to be a poor store of oil and gas. A sedimentary basin with poor deliverability tends to attract sparse seismic coverage and well data, which ordinarily provide the material for a thorough understanding of the basin.
Among the 13 African countries classified as oil producers, Côte d'Ivoire ranks only higher than South Africa. With an estimated 100 million bbl of recoverable reserves of oil, it ranks lower than the war-torn Democratic Republic of Congo (200 million bbl). With 20,000 b/d of oil, it produces less than one hundredth of Nigeria's daily output. Earth scientists started poring over geologic data in the country at the beginning of the century when tar sands were discovered in parts of Côte d'Ivoire. But it wasn't until 1953 when active oil exploration began.
Still, Côte d'Ivoire would not become classified as an oil rich country until Exxon discovered the Belier Field in 1974. Oil production did not start until 1980, and even in that short range of time, the history can be divided into two distinct production phases.
First production phase
The first phase runs from 1980 - when Belier was placed onstream and Côte d'Ivoire joined the league of oil producing nations - to 1992. The second phase runs from 1993 to the present. In the first phase, Exxon made six discoveries, including Belier, which came onstream in 1980, producing from Lower Senonian sandstones. - The Abidjan Margin, bounded by the St. Paul fracture zone in the west and the Romanche fracture zone in the east.
Phillips drilled many wildcats between 1979 and 1985, two of which turned out to be the Assinie and B 3X gas and condensate field discoveries. The company discovered Espoir in 1980 and put it onstream in 1982, producing an average of 14, 000 b/d of oil. Phillips also discovered the Foxtrot field in 1982, but did not produce it. Agip discovered A1-2X in 1982.
Depressed oil prices and accelerating depletion compelled Phillips to shut down the Espoir Field in 1988, after producing 31 million bbl of oil with a gravity of 29-33° API and flaring 62 Bcf of gas. It was also during this first production phase that the state oil company, Petroci, made their first discovery. In 1988, the company encountered the Gazelle gas and condensate accumulation, 1 km east of Ivco-12 in the Belier Field. It also drilled an oil well, Outpost 1, about 1.5 km to the north-northwest of the Belier discovery well, Ivco-4.
Meanwhile, Exxon produced the Belier field for a longer stretch of time. Belier delivered some 20 million bbl from Lower Senonian sandstones, averaging 4,500 b/d of oil before shut-in in October 1992.
The oil exploration scene became very quiet in Côte D'Ivoire with the exit of Phillips (1988) and Exxon (1992). At about the same time, the economy stepped into decline with the collapse of prices of agricutural products - its mainstay.
Second production phase
United Meridian Corporation (UMIC) arrived in Côte d'Ivoire in the same year that Exxon shut in production of the Belier field. The company signed a production sharing contract (PSC) on Block CI-12 in January 1992. The Lion Field was discovered in February 1993, flowing 23,696 b/d of oil. The field went on production in March 1994, 27 months from PSC and only 13 months after discovery. The gas field, Panthere, was discovered in December 1993, testing 30 MMcf/d of gas and 942 b/d of condensate. After helping Côte d'Ivoire to get back into the league of oil producers, a putative gas supplier, UMIC, installed the country's first gas field electricity plant.
All this had taken place by October 1995, less than four years after UMIC signed the PSC. The volume of gas utilized by that plant increased to 80,000 MMcf/d from 55MMcf/d in June 1997.Thus UMIC (now Ocean Energy) also gave Côte d'Ivoire the first West Africa commercial gas field development, enhancing the country's claim as "The Elephant of Africa." Côte d'Ivoire is appreciative of UMIC's help in restoring the country's economic health.
Abidjan Margin geo-dynamics
Côte d'Ivoire's main attraction for investment has not been due to the volume of its oil pools, but rather the country's historically favorable infrastructure, stability, and consistency in economic development. Oil operators have been comfortable exploring in Côte d'Ivoire, and managed to assemble a wealth of data to provide insight into the evolution and the geo-dynamics of the Abidjan Margin.
Two recent papers have attempted to explain this unique geology, with data from more than a hundred wells, an extensive 2D seismic grid, rapidly increasing 3D seismic data, and several producing fields.
The more groundbreaking of the two papers is a work by two Ocean Energy earth scientists, J. C. Harms and R. L. Wallace, entitled "A Petroliferous Transform Margin Basin, Côte D'Ivoire, West Africa." A less detailed paper, assembled more for hydrocarbon prospectivity than geologic insight, is "A Sequence Strati graphic Approach to Exploration and Re- development in the Abidjan Margin," by Ranger Oil's Justin Morrison and three other earth scientists from Petroci.
Both theses disclose that the Abidjan margin, located predominantly offshore, is a break-up transform margin, formed by large dominantly strike-slip faults which were generated by the separation of the continents.
The basin runs from Côte d'Ivoire into Ghana, bounded to the east and west by the Romanche and St. Paul fracture zones (which are major strike-slip faults themselves). "A continental margin defined by such a transform zone is sharp, precipitious, and places an essentially complete continental crust abruptly against oceanic or highly attenuated continental crust," according to Harms and Wallace.
Structural framework
"Structures develop in stress fields dominated by horizontal translation with overprint of uplift and subsidence related to thermal effects of a laterally migrating asthenosphere plumes," wrote Harms and Wallace. Their paper identifies three main structural and morphologic features along the Abidjan Margin:
- A very steep and narrow (20-30 km) transition between the continental domain and an adjacent oceanic abyssal plain, indicating a very sharp crustal transition between thick or only partially thinned continental crust and oceanic lithosphere (the Côte d'Ivoire coastline), which is in a lateral continuity with the St Paul Fracture Zone
- A broader area of transition between the continental domain and the abyssal plain underlain by a transitionally attenuated continental crust (the curved coastline and shelf of eastern Côte d'Ivoire and western Ghana)
- A morphologically well expressed marginal ridge between attenuated continental crust and oceanic crust (The Côte d'Ivoire-Ghana Marginal Ridge) and its seaward extension into a major oceanic fracture zone.
The basin evolved from a strike-slip situation, dominated along the east-west trending major fault zones, linked by north-south trending rifts, through a stage of crustal attenuation and development of oceanic crust to a final phase of isostatically and thermally controlled sudsidence. "Into these complex developing and changing basins, sediments from upland were deposited, and formed prograding shelves, slopes, and deepwater fans," Harms and Wallace state.
Sedimentary succession
Deepwater lacustrine facies of Aptian-Albian age were deposited during the syn-rift phase, and make up the base of the stratigraphic sequence, which exceeds 5,000 meters in places. These syn-rift sediments are overlain by Albian marine sediments, Products of marine incursion which began when the ocean connections developed after the opening. Deformation, uplift, and probable sub-aerial erosion, in the later Albian developed in the forming basin. At the end of the Albian, after the continental opening, a series of delta and submarine fan systems deposited Upper Cretaceous sands across the Abidjan Margin.
The basin subsided rapidly after opening and crystalline uplands rose in the central and western part of Côte d'Ivoire, presumably a reaction to heat transfer related to regional mantle upwelling or to local heating at the eastern end of the St. Paul fracture zone. There, isotherms in the asthenosphere had risen substantially.
The combination of a deep basin and adjacent uplands developed a system of very narrow alluvial plains, a narrow shelf, and a slope transition abruptly into deepwater. This topography and bathymetry favored emplacement of turbidite fan complexes which were quite sandy in the western Côte d'Ivoire. Toward the east, because uplift of highlands had not been so substantial, the basin was filled with largely muddy sediments. Apparently, through the Aptian and up into some part of the Albian, connection of the deep Côte d'Ivoire basin to the South Atlantic or North Atlantic had not been accomplished, so that the water body was essentially fresh or at least of such low salinity that marine forms were generally excluded.
Harms and Wallace attribute the change, from lacustrine to marine conditions, to a relative sea-level rise. Evidence of a broadly correlative marine shale indicates sand supply to the basin was reduced, perhaps equating to a eustatic higher stand.
As the attenuation or spreading center migrated westward, a period of deformation, possibly thermally related, occurred and deformed Albian sediments. A series of rotated northward-dipping oblique fault blocks developed.
By the upper Cretaceous, around the Cenomanian, the water deepened and the outer series of highs typical of the eastern Côte d'Ivoire received pelagic carbonate deposits, while the deeper basin to the north was filled with a combination of mud and sandy turbidities, Harms and Wallace testify.
"During low stands of sea level, turbidities may have found their way through erosional depressions in the outer ridge and into the deeper offshore basin," the two scientists disclosed. At other times, the turbidities were confined to relatively small fans supplied by streams and/or canyon which cut across a shelf which was somewhat broader than that of Albian time. In some areas, Cenomanian was not deposited because of local bathymetric highs or was later eroded by Senonian channels or canyons.
Deposition appears to have followed a similar pattern of narrow shelf, slope, and deeper water turbidites which prograded southward throughout all of the Upper Cretaceous (Cenomanian, Senonian). Throughout this time span, much as now, sand appears to have been supplied by a relatively small number of drainages from Côte d'Ivore uplands and across the shelf into deepwater as fan complexes during periods of relatively low stand of sea level.
Three major modern drainage basins dominate the country and have by far the largest water and sediment discharges. The pattern may have been very similar in the Cretaceous, with the major sediment routes spaced at 100-130 km. Drainages with higher proportions of sand appear to have developed later in the eastern Côte d'Ivoire, so that sandy turbidite sand complexes can be found in the Maastrichtian (the youngest Cretaceous), whereas they appear to nearly absent in the Albian.
The sands appear to become progressively more mineralogically mature as the sedimentary sequence gets younger. Maastrichitan sands are essentially pure quartz arenites. There is a down-section increase in feldspar and mica, so that within Albian-age sediments, the sandstones are micaceous arkoses with only about 50% quartz. As a result of these mineralogic differences, Albian sediments appear to be much more subject to detrimental diagenetic alteration than are the younger sandstones.
The upward increase in mineralogic maturity through the Cretaceous suggests changes in the transport and depositional systems. Because all the sediments were likely derived from the crystalline uplands of northern Côte d'Ivoire, the increase in mineralogic maturity of younger sandstones may reflect a combination of reduced relief in the uplands and a broader alluvial coastal plain as time passed.
Reduced relief would allow slower erosion and more thorough tropical weathering before sediment entered the stream systems. A broader alluvial plain might cause longer residence time of sediments in a reworking and weathering environment before final transport into the deeper water basin.
Later, in the Tertiary period, deposition continued in shallow marine shelf, slope, and bathyal environments, with the general progradational southward advance of the shelf margin to its present site. Seismic data show many examples of prograding clinoforms, representing deposition during high or stable sea-levels stands, and deep canyons, representing erosion during relatively low stands..
Petroleum occurrences
The Espoir field, a bilobate structure, is essentially Albian in age. As of 1988, when Phillips abandoned it, Espoir was producing well above 10,000 b/d of oil. It was abandoned because prices had dipped far below the cost-per-barrel that was factored during the Field Development Plan in 1982. Now Ranger Oil is re-developing the field, and hopes to produce 80 million bbl of oil more from an ultimate reserve estimate of 480 million bbl.
Source rocks have been identified in the syn-rift Albian lacustrine shales and multiple Upper Cretaceous marine claystones, according to Morrison et al. Integrated sequence stratigraphy has enabled the description of the productive facies in the various oil fields. The middle Albian turbidites are the reservoirs in the Foxtrot gas field and upper Albian turbidite/ delta sandstones are the reservoirs in the Espoir and Lion oil fields.
The delta and submarine fan systems in the Cenomanian have produced the gas reservoirs in the Panthere Field. The same facies of sands from the Senonian hold the oil in the famous Belier Field. Morrison et al's work has also identified regional reservoirs in the middle Albian, Upper Albian, Cenomanian, Lower Senonian and Maastrichtian which could have been carried as far as the deepwater segments of the Abidjan margin.
Studies have deduced that larger pools can be encountered deeper in the Albian section than is currently tested. But Cenomanian and Lower Senonian reservoirs have so far turned out to be smaller than Albian sands. As Belier has shown, they are trapped in unpredictable and discontinuous sand lenses deposited in a deep-sea fan environment.
Correlation of the seismic data with high resolution biostratigraphic data, far into the deep offshore, have revealed Apto-Albian syn-rift reflections as large prospects. And there is a Cenomanian basin, named the Grand Bassam sub-Basin, located to the south of the shelf break, created during continental breakup at the end of the Albian.
Deepwater hydrocarbon plays present in the Grand Bassam sub-basin include Apto-Albian synrift sandstones in the intra-basinal highs, Cenomanian and younger sand drapes over intra-basinal highs, Albian sands in the tilted fault blocks, and multiple sandstone pinchouts on the south side of the shelf break in the Cenomanian, Lower Senonian, and Maastrichtian.
Potential
The Abidjan margin has proved that it can deliver small-medium sized fields (30-100 million bbl of oil) in shallow water. Huge prospects (200-1,000 million bbl) appear more likely in deeper water and these have only recently attracted serious exploration.
One calculation has it that the greatest potential for significant Albian reserves lies in deepwater (>600 meters) and there are at least five large structures with closures greater than 25,000 acres. This calculation adds that such structures are most likely gas plays, because of the depth of the hydrocarbon kitchen.
In 1995, Ocean Energy concluded that expected recoverable reserves in deepwater may be as much as 3.5 billion bbl of oil. The risk is that many of the 26 structures, which makes up this 3.5 billion, may not be large enough to justify development of some part of this resource potential.
Business environment
Much of what has kept Côte d'Ivoire going as an oil exploration province, in spite of its marginal oil reserves, has been the government's incentives. The petroleum legislation offers:
- A period of exploration of 7-9 years (up to three periods); an evaluation period of two years, and a exploitation period of 25 years. Incentives include total remission (absence) of TVA; maximum of 48 hours of customs control; and abolition of SGS controls.
- In the level of recovery, operator costs can be 75%, the possibility of monetary recovery, the supplementary operator costs are negotiable, an extention of agreed fiscal advantages for the enterprise, and a negotiable period.
- Coverage of exploration is 25% of surface by the end of the 1st period, and 25% of surface by the end of the 2nd period
- Requirements during exploration include negotiations, work priority, report of exploratory wells, bonus, abandonment, and change control.
Ranger plans to re-develop the Espoir Field and put it onstream. Espoir is a bi-lobate structure which covers some 30 sq km in area. Phillips produced 31 million bbl of oil in six years between 1982-1988, with 62 bcf of gas flared. Using Phillips' production history and 3D seismic lines of 1981 vintage, Ranger estimates there are remaining 80 million bbl oil recoverable.
Apache has put the Foxtrot gas field onstream, but it is being careful not to commit too much to capital intensive projects before it generates adequate cash from existing commitments. Operators have been cautious about investing in deepwater leases, which are the future of the Abidjan Margin. Because of the steep bathymetry, most of the leases have shelf and deepwater (slope) parts.
What is more, for all its incentives and relatively good infrastructure, the Abidjan Margin doesn't attract the majors. The basin has shown itself to be more a playground for independents. Even so, some of the independents are quite keen, such as Vanco Energy, Ranger, Santa Fe, and Apache.
With 700 sq km of new 3D data, Ocean Energy mapped three tertiary channel plays, two of which resemble Elf's Girrassol structure in deep offshore Angola. The company drilled its first well in the deepwater in October of last year. The well was in East Grand Lahou-1 and was plugged and abandoned as a dry hole at a total depth of 3,592 meters. The company is evaluating the results to determine if it was poor placement of the well location that led to the disappointing results, or the geology itself.
It is assumed that the country's lackluster environment last year was due to the depressed oil prices, which led to budgets that could not be easily revised, even as prices went up.
