Detailed study leads Repsol to offshore West Africa

Dramatic changes in the global economy, and specifically the oil and gas industry, have led to a greater interest in development of new upstream resources.

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Stefano Mora
Roger Baudino
Repsol

Dramatic changes in the global economy, and specifically the oil and gas industry, have led to a greater interest in development of new upstream resources. As a result of many of these sweeping changes, Repsol chose to pursue a greater presence in the West African region throughout 2011.

At the beginning of 2003, the majority of exploration and production news out of Africa was concerned with the competition between oil and gas majors and their ability to expand their asset portfolios in deepwater offshore areas. This drive focused initially on Nigeria and Angola, and then came renewed interest in countries such as Gabon and Congo, places considered newly mature for exploration. The discovery of large deposits in deepwater offshore from Mauritania seemed to indicate the emergence of a new oil province in the African-Atlantic margin.

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The West Africa margin area investigated by Repsol.

Repsol needed to find new reserves to replace its maturing fields, especially those in Argentina. For Repsol, the inherent difficulty in finding replacement resources for its Argentinian fields was the need to find an innovative strategy to avoid competing financially with other oil and gas majors, yet not compromise production.

Repsol approached this new challenge by posing two questions:

  • What would be the new hot area for exploration?
  • Which markets would be the least competitive to enter while also providing the greatest potential for oil?

For Repsol, the answers were found using documented evidentiary research.

First, Repsol began to build an extensive seismic database spanning tens of thousands of kilometers covering the Atlantic region of Africa, from Ceuta to Cape Town. This database then was cross referenced with hundreds of potential wells. After more than a year of painstaking work, the West Africa New Venture Department began to highlight some promising areas for further study.

These results helped push Repsol in the right direction, but they also highlighted a pressing problem: The data presented technical risks and from the initial impressions, the possibility of success seemed unlikely.

Although the data were discouraging, Repsol did have valuable experience with risky, ultra-deep offshore extraction. The company already was looking into promising but risky locations in the Brazilian ultra-deep offshore margin. The true challenge was to balance the need for greater exploration and development without overstretching Repsol's capabilities.

Repsol realized it needed to introduce another parameter to its screening of potential opportunities. Specifically, this meant exploring and understanding the types of contracts Repsol was eligible to sign in order to begin exploratory work. Economists from the planning department joined the project in an attempt to identify specific areas where contractual terms would allow the company to maximize its rewards if successful but to mitigate the impact of unavoidable failures.

With the remaining selection of deep offshore basins, Repsol ultimately decided the most intriguing were those between Benin and Senegal. In part, these areas revealed a much greater potential than some others. Most importantly, however, the area between Benin and Senegal was chosen because there were no other oil majors operating within that area. This allowed Repsol to balance its opportunities with the potential downside risks that direct competition with other oil majors would bring.

During the first half of the 20th century, many areas offshore West Africa already were explored extensively, beginning with the first discoveries along the coast of Nigeria. This exploration was successful in the Tertiary and Mesozoic series; specifically, successful opportunities were identified in the passive regions characterized by active salt tectonics (as existed in Angola, Congo, and Gabon) and in the Tertiary series of passive regions associated with the development of large deltaic systems (which was the case in Nigeria, Cameroon, and Equatorial Guinea, in addition to the Congo and Angola).

However, the Equatorial Atlantic region between Benin and Senegal, which is connected to the transfer zone between the northward propagating tip of the South Atlantic and the southward propagating tip of the Central Atlantic, had been explored for several decades with disappointing results. In fact, the Lower Cretaceous region showed poor reservoir properties and the quantities of hydrocarbons discovered were extraordinarily small.

The Baobab field, discovered in Ivorian deep water in 2002, was a notable exception. Seismic data showed Canadian Natural Resources had drilled the largest structure lying along the equatorial margin.

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An example of 3D geochemical modeling, showing the levels of maturities along the transform Atlantic margin of Equatorial Africa.

In other words, the discoveries in the margin exhibited relatively poor reservoirs, small structural closures, and < source rocks. The seismic data interpretation showed 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 seal and pressure studies demonstrated the shales were able to seal relatively large columns of hydrocarbons.

The other main uncertainties included reservoir quality (especially permeability), and the effects of source rocks and migration. Although Baobab-1 illustrated that a working petroleum system could exist, a deeper understanding of the stratigraphic position and the typology of source rocks was crucial to defining an exploration strategy. As a result, it was important to ascertain whether all components of the existing petroleum system were operating efficiently, including source rocks, reservoirs, seals, and traps, in order to generate and contain sufficient volumes of oil.

A basin modeling exercise was performed to better assess the petroleum system in this area. Thermal and maturity data for calibration were, as usual, scarce in such a frontier area. Thermal gradient findings showed a variation between 31º and 36º C/km (88º and 97º F/0.6 mi). While illuminating, these findings could not be used as a constant. The largely unexplored environment required Repsol to apply its understanding of global dynamics by analyzing plate tectonics and earth structure. Indeed, the regional nature of a rift basin evolving into a passive margin implies huge variations of the thermal gradient through space and time. Ultimately, Repsol decided to apply a heat flow at the base of the sediment which helped clarify these variations.

Closer to the coastline, on a stable non-stretched continental crust, temperature and maturity data could be calibrated using a constant heat flow over time. However, the ability to maintain constant heat flow became impossible. Instead, a rifting heat flow was applied, characterized by a peak during stretching and a progressive cooling in line with the existing McKenzie and Royden models.

The findings concluded that large areas of several source intervals actually had sufficient maturity to generate gas, as well as large volumes of oil, around the Equatorial West African margin.

From the seismic stratigraphy interpretation and attribute analysis, Repsol mapped the sedimentary assemblage of the turbiditic systems. The results showed several interesting prospects. However, the study of subsurface analogues showed that at similar depths for the same reservoir facies, the porosity values could vary from 3% to 25% due to diagenetic processes.

These results revealed the greatest uncertainty about this project: Repsol was confident regarding the presence of oil, but less so about whether the reservoirs were adequate.

Repsol then attempted to model the diagenetic processes following a detailed petrologic study coupled with temperature and fluid-flow information produced by the petroleum system model. Although this improved the understanding of diagenetic alteration, it did not develop any predictive results.

Uncertainty remained. Repsol could not adequately predict the quality of the reservoir nor assess its ability to store and produce liquid hydrocarbons. This is not uncommon when diagenetic processes are concerned, especially since they are controlled by many factors that can vary greatly even over small distances (compactions, grain size, grain composition, type of circulating fluids, hydrothermal events, volcanic events, etc.).

It is rare, however, for an oil company not to drill when it believes a reservoir exists.

Although oil companies ought to make decisions based on the highest standards and analytic techniques, this case study illustrates that some parameters always remain beyond control. The gap between what explorers can control and what they can actually analyze explains why many oil companies take a leap of faith to pursue an aggressive exploration strategy. It is this strategy that leads to innovative methods of exploration and the discovery of new sources of oil previously out of reach.

How do an aggressive exploration strategy and a rigorous technical analysis help to build new sources for consistent future development?

In 2004, the maps of concessions in the Equatorial Atlantic margin offshore of Africa show Repsol as the only oil major holding exploration permits. Woodside also held a block in Liberia, but a majority of the area was dominated by small African firms and a handful of other small companies focused entirely on exploration.

How and why did this change?

Repsol's exploration strategy acted as a catalyst, triggering the industry's shift to focus on offshore West Africa. The latest update of oil and gas maps of West Equatorial Africa shows that Kosmos and its partners have produced the first oil from Jubilee, while Repsol and its partners have made the Venus and Mercury discoveries. In other words, these maps show that oil majors now have a significant presence in the region, and have several appraisal and exploration wells planned for the next few years.

The systemic uncertainties involved with oil and gas exploration, especially in deepwater offshore, can make explorers unsure of their strategies. However, pioneering exploration coupled with risk mitigating geological analyses can help minimize the uncertainty involved with attempting to explore and cultivate new sources of oil.

The Authors

Pennwell web 120 150Stefano Mora serves as new venture manager for Africa at Repsol. He joined the company in 2007. Previously, Mora spent nearly 15 years at Total. His oil and gas industry experience is in basin analysis and his main research interests include tectonics and sedimentation, seismic and basin modelization. He received his MSc and PhD from Parma University, Italy.
Pennwell web 115 150Roger Baudino is a senior exploration geologist and works as a senior advisor in the geology disciplines group at Repsol. He has a PhD in sedimentary basins geodynamics and structural geology from the University of Pau (France). He has been involved in numerous projects around the world, mainly in Latin America. He joined Repsol-YPF in 2003. He earned a BSc from Nice University (France), and both a MSc and PhD from Pau University (France).

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