Repsol is pioneering in the African Atlantic margin

At the beginning of 2003, all the E&P news was about the competition between the oil and gas majors to expand their portfolio of assets in the deep offshore areas of Nigeria and Angola as well as in countries considered mature for exploration, like Congo and Gabon, there was a strong renewed interest. The discoveries in the deepwater offshore Mauritania seemed to indicate the emergence of a new oil province in the African Atlantic margin.

As a company, we faced the dilemma of needing to find new reserves to replace maturing fields, especially in Argentina, and having to do so without being able to compete economically with the other majors. Hence our brains needed to do the work that our pockets could not.

Thus we asked ourselves two questions: What would be the new hot area for exploration? And where could we find the areas with great oil potential and with a low level of competition?

The first step was to collect and examine existing data and studies in order to sustain our hunches with reliable facts. First, we began to build an extensive seismic database of several tens of thousands of kilometers covering the Atlantic margin of Africa between Ceuta in the north and Cape Town in the south, and to integrate that database with hundreds of wells. After more than a year of interpretation, the West Africa new venture department highlighted some promising areas.

The initial results highlighted another problem: As expected, all the plays were very risky from a technical point of view, and the chance of success was low from first impressions. Repsol was already looking into what were then promising but also risky areas in the Brazilian ultra-deep offshore (Those areas ended up yielding world-class successes, but that is a different story), and the company needed to be able to find new opportunities that would not stretch our capabilities in excess.

Thus in West Africa we needed to introduce another parameter for screening the potential opportunities, namely the type of contract that could be signed to begin exploratory work. The economists from the planning department joined the project to try to identify the areas where the contractual terms would allow us to maximize rewards in case of success and consequently mitigate the impact of the unavoidable failures.

Of the areas remaining, the deep-offshore basins between Benin and Senegal were ones which were most intriguing. This area was not only worth doing more work on, but was also advantageous in that at the time there was no presence of the oil majors there.

The West African offshore had been explored since the first discoveries along the coast of Nigeria in the first half of the past century. That exploration had been successful, both in the Tertiary and in the Mesozoic series in the passive margins characterized by active salt tectonics such as Angola, Congo, and Gabon, and in the Tertiary series of passive margins associated with the development of big deltaic systems, as was the case in Nigeria, Cameroon, Equatorial Guinea, and again in Congo and Angola.

However, the Equatorial Atlantic margin between Benin and Senegal associated to the transfer zone between the northward propagating tip of the South Atlantic and the southward propagating tip of the Central Atlantic was explored for several decades but with very disappointing results. The Lower Cretaceous objectives showed poor reservoir properties, and the discovered hydrocarbon accumulations were very small.

The only notable exception was the Baobab field, discovered in 2002 in Ivorian deepwater, but a quick look on the seismic database showed that Canadian Natural Resources drilled the largest structure existing along the transform equatorial margin.

So, relatively poor reservoirs, small structural closures, and a not-well-defined source rock. The seismic interpretation shows a relative abundance of well-developed turbiditic systems across all of the mid- and upper-Cretaceous section. The main trapping mechanism was of course stratigraphic, but the seal and pressure studies show that the shales are able to seal relatively large hydrocarbons columns.

The main remaining uncertainties are reservoir quality, especially in terms of permeability, the source rock effectiveness, and the migration. In fact even though the existence of a working petroleum system was proven by the Baobab-1 well results, the stratigraphic position and typology of the source rock was crucial to define an exploration strategy. In addition, from an economic perspective, the lack of a market for gas made oil accumulations the only viable discovery.

So the first question to answer was if there was an effective petroleum system – that is, source rock, reservoirs, seals, traps, and adequate timing, to generate and trap sufficient volumes of oil to make prospects economically viable.

In order to assess the petroleum system in this area a basin modelling exercise was performed making the following assumptions: Seven source rocks were considered after reviewing the evidences on both sides of the Atlantic: some in the rift sequence of the Early Cretaceous age (mainly lacustrine or restricted marine), which were well documented on the Brazilian side, and others in the drift sequence of Mid to Late Cretaceous and Tertiary age (mainly open marine environment).

The number of potential source layers may appear high, but experience shows that few basins have no organic rich sediments. The crucial point is to know if they have a suitable extension, thickness, richness, and maturity to generate commercial volumes of hydrocarbons.

The kinetic scheme assigned to each type of source was derived from reference kinetics available in the company. Indeed, no analysis was available from local samples, and we had to rely on worldwide references and, when available, equivalent in age and sedimentary environment.

Thermal and maturity data for calibration were, as always, scarce in such frontier areas. The present thermal gradient issue from existing data is between 31 and 36 degrees C/km. However that couldn't be used as a constant. In this kind of complex and largely unexplored environment you have to rely on science of global dynamics going back to plate tectonics and earth structure. Indeed, the regional setting of a rift basin evolving to a passive margin implies great variation of the thermal regime through space and time. It was then decided to apply a heat flow at the base of sediments that would allow us to better picture those variations.

When close to the coastline, on a stable non-stretched continental crust, temperature and maturity data could be calibrated using a constant heat flow through time. Toward the deepwater it was impossible to calibrate data with the same or any constant heat flow. In this area, we applied a rifting heat flow characterized by a peak during stretching and a progressive cooling following the McKenzie and Royden models.

The model concluded that large areas of several source intervals had reached sufficient maturity to generate gas but also large volumes of oil. Thus, the model was suggesting that there was a real potential for oil and a chance to discover important accumulations in this area of the Equatorial West African Margin.

From the seismic stratigraphy interpretation and attribute analysis, the sedimentary assemblage of turbiditic systems was mapped. This allowed us to define several interesting prospects. However, the study of subsurface analogs showed that at similar depths for the same reservoir facies the porosity values could vary from 3% to 25% due to diagenetic processes. This then became the main uncertainty since we were much more confident regarding the presence of oil. Would we find adequate reservoirs?

We tried to model the diagenetic processes after doing a detailed petrologic study coupled with temperature and fluid flow information produced by the petroleum system modelling. Indeed we greatly improved our knowledge of diagenetic alteration but without being able to be confidently predictable. Uncertainty remained regarding the quality of the reservoir and its ability to store and produce liquid hydrocarbons.

This is not uncommon regarding diagenetic processes since they are controlled by many factors that can greatly vary in small distances (compaction, grain size and composition, type of circulating fluids, hydrothermal events, volcanic events, etc.) But rarely would one not drill a well if one thinks that a reservoir exists despite doubts surrounding the quality thereof.

And here is where every explorer has to take a risk, a leap of faith. Although an educated guess based on the highest standards of technique must always be made, some parameters will remain beyond control. But big rewards will only result from an aggressive exploration strategy.

Yes, an aggressive exploration strategy! Back in 2004, when looking at maps of concessions in the Equatorial Atlantic offshore of Africa, one could see that Repsol was the only major holding exploration permits in the area. Woodside held a block in Liberia, and the rest of the area was dominated by small "100% pure exploratory companies" and small African companies. Were we wrong? Were we crazy? Or were we pioneers?

I look at the last update of oil and gas map of West Equatorial Africa: Kosmos and its partners have produced the first oil from Jubilee. Repsol and its partners have made the Venus and Mercury discoveries. And the majors are now present en masse in the area, and several appraisal and exploration wells are planned for the next few years.

Have we been good explorers? Personally, we prefer to be thought of as pioneers. An explorer goes into a new country, observes, makes contacts, studies maps, collects some samples, and eventually goes back home. A pioneer stays and builds the future.

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