HRT advances plans offshore Namibia

The company's senior management has significant technical knowledge and operational experience in the Brazilian and western African sedimentary basins. Their Brazilian onshore and offshore E&P activities provided extensive environmental expertise and regulatory knowledge of the Brazilian oil and gas industry.

Measured by acreage, HRT believes it is one of the largest independent Brazilian E&P oil companies. Its exploration portfolio includes approximately 75,425 sq km (18.6 million acres) in onshore blocks in the Solimões (Amazon), Espírito Santo, Recôncavo, and Rio do Peixe basins in Brazil. Offshore, HRT holds blocks in the Walvis and Orange sub-basins in Namibia.

HRT is a holding company with two wholly owned subsidiaries: IPEX and HRT O&G. Up to July 17, 2009, it was a privately held corporation. The company was incorporated on October 13, 2008, as a Brazilian limited liability company.

In this exclusive interview withOffshore, Wagner Peres, president of HRT America, provides an update on his company's efforts offshore Namibia, West Africa, and describes the geological similarities between the South American and West African southern margin basins.

Offshore: To start, perhaps you could describe the concept of continental drift, and how it impacts the possibility of finding oil in the Namibian presalt.

Peres: The offshore basins of the southern Atlantic share a common evolution history. Although South America and western Africa are separated by the vast Atlantic Ocean today, in the geologic past when the petroleum basins were forming, they were one province with a common history. The offshore Brazil and South America petroleum basins have been heavily explored and are prolific oil-producing provinces. Where offshore West Africa has been heavily explored, it too is a prolific oil producer (e.g. Nigeria, Angola, etc.). Offshore Namibia has not been explored enough to determine its real potential. However, the few wells drilled in the area so far have already shown signs of containing a similar and significant petroleum province.

The similar natures of the petroleum basins can be explained by plate tectonics, formerly known as continental drift. The continents of South America and Africa are part of the Earth's outermost layer of plates, known as the crust. The plates move relative to one another as they ride atop hotter, more mobile material, known as the mantle. As a result, the surface of the Earth – the position of the continents – looked very different in the past than it does today. Approximately 144 million year ago (mya) in the Berriasian Stage of the Cretaceous Period, the present continents and land masses of South America, Africa, Arabia, India, Antarctica, and Australia, formed a single land mass in the southern hemisphere known as Gondwana. More specifically, South America and Africa were joined as one land mass. This is important because it means that the petroleum basins of offshore West Africa share a common geologic history with the petroleum basins of South America. Then, beginning in the Early Cretaceous Period around 136 mya, the South America and African plates began to break up (rift) and separate (drift). As the land masses separated, the plates drifted apart in a punctuated fashion, from south to north. South America and Africa thus began their separate histories.

The reconstruction of the continents is reinforced by the correlations of oil families between South America basins and West African basins. This is illustrated when comparing the oil families from the Campos basin with the oils from Kwanza basin in Angola, as well as correlations from areas further north such as Reconcavo basin (Bahia State, Brazil) and the Lower Congo basin and further south, like the Santos basin south of Brazil and the Orange basin in Namibia.

The Resource Assessment information published by Degolyer & McNaughton (D&M) in 2011 and early 2012 is the most up-to-date report of "numbers" available regarding HRT's hydrocarbon resources in Namibia.

Offshore: Knowing how petroleum systems evolved in the area with respect to areal and stratigraphic limits helps define the similarities between the African and the Brazilian resources. How does the history of continental drift fit into your company's vision?

Peres: Because the basin-forming processes and paleo-climates were the same, there are striking similarities between the basins in West Africa and in Brazil. These similarities have resulted in closely comparable petroleum systems distributions and properties for much of the margins.

The initial rifting of Gondwana land led to the formation of a series of rift valleys as the crust stretched and thinned prior to the complete separation of the African and South American plates. These rift valleys generally contained lakes in which excellent quality lacustrine source rocks were deposited, so that rift lacustrine sources are quite common on both margins. Because at the time of rifting these valleys were in proximity and were subjected to the same geologic and paleo-climate conditions, they have similar source rock properties and similar oil properties on both sides of the Atlantic. This has been demonstrated by the correlations of rift lacustrine oils from Brazil to those in West Africa.

Almost all the basins in the South Atlantic appear to contain rift intervals and almost all the rift basins that have been adequately tested in the South Atlantic contain lacustrine petroleum systems. Consequently, rift lacustrine systems are major sources of oil in the South Atlantic (e.g., the Bucomazi in West Africa, the Lagoa Feia in Brazil).

When the two continents were completely separated, a narrow seaway was formed between them with restricted circulation and widespread anoxic conditions. As a result, this seaway was a favorable area for deposition of marine source rocks just above the last of the rift-associated sediments (or the salt if north of the Walvis Ridge – northern Namibian offshore) as the seaway initially flooded onto both continental margins (which were still close together). Although the ages vary from Aptian (about 120 mya) to Albian (about 110 mya) from south to north due to the different times that the seaway opened, these early transgressive sources occur commonly on both sides of the Atlantic, including basins in Namibia, Equatorial Guinea, and Brazil. Their importance to oil generation and accumulation depends in large part on the levels of maturity. In some areas (e.g., the Campos basin), they have not been buried deeply enough to generate oil, while in other areas they are generating oil.

As an open Atlantic Ocean developed, geochemical and geological processes diverged between the African and South American margins. However, in the Cenomanian and Turonian (the "C-T," about 93 mya), due to reasons not fully understood, circulation in most of the South Atlantic periodically became restricted and much of the bottom of the water column became anoxic. During these times, high-quality marine source rocks were deposited regionally across the South Atlantic, from Senegal and Equatorial Brazil down to South Africa. Although the C-T sources in Brazil and West Africa (e.g., Namibia) have very similar properties and generate similar types of oil, their importance to oil accumulations again varies locally with levels of maturity. In addition to the C-T events, oceanic anoxia developed at other times, but these episodes appear to be less conducive to regional source deposition. A new resource study is planned for August, 2012.

Offshore: Please explain the general similarities and differences between the South American and West African southern margin basins, such as the Congo and Kuanza basins in Angola and the Orange basin in Namibia.

Peres: While the systems on the two sides are parallel, there are important similarities as well as some significant differences, due to localized conditions. In some areas we can make a direct, one-to-one comparison, while in other areas such comparison would be difficult without an understanding of local influences.

There are a number of examples of the similarities. These include the basin-forming processes and paleo-climates; and comparable petroleum system distributions and properties. The initial rifting of Gondwanaland led to the formation of a series of rift valleys on both sides of the margin. Rift lacustrine sources are common on both margins; the lacustrine sources have similar rock properties demonstrated by the correlations of rift lacustrine oils from Brazil to those in West Africa. The rift lacustrine systems are major sources of oil on both margins – for example, the Bucomazi in West Africa and the Lagoa Feia in Brazil.

A narrow seaway was formed between Africa and South America with restricted circulation and wide spread anoxic conditions depositing marine source rocks on both margins. In the Cenomanian and Turonian, circulation in most of the South Atlantic periodically became restricted and much of the water column became anoxic. During these times, high-quality marine source rocks were deposited regionally across the South Atlantic, from Senegal and Equatorial Brazil down to South Africa.

There are some differences as well. Much of the source in offshore Angola (the Iabe) doesn't have an equivalent in Brazil, making comparison of the Angolan basins to Brazil difficult. Similarly, as noted above, the Bucomazi is more syn-rift than transition to drift. In addition, geothermal gradients in Namibia are much hotter than most of the Brazilian margin. Lastly, much of West Africa has been influenced by uplift and erosion, which is not a significant factor in Brazil.

Offshore: Have HRT studies identified the approximate volume of 7.9 Bboe potential in Namibia, in terms of reserves of all offshore concession areas, through 2D seismic surveys only? What was the role of geochemistry? Is this result so far being confirmed, or do the 3D resources show more detail and reveal more? Do you expect any changes in this first estimate as a result of 3D?

Peres: Yes. HRT O&G identified leads and prospects offshore Namibia with well information and 2D seismic data purchased from Namcor and commercial vendors (who currently have extensive inventories of 2D seismic data in offshore Namibia). The identified leads and prospects were then passed to D&M where their staff confirmed the existence of the features and performed prospect risking and volume assessment. The 7.9 Bboe from the HRT website represents a risk-weighted volume.

The principle role of petroleum geochemistry in identifying and quantifying the petroleum potential is in establishing the oil-prone nature of the area and in validating the charge adequacy of the petroleum systems. In other words, the geochemistry evaluations showed that offshore Namibia was a viable area for oil exploration.

To be specific, the geochemistry evaluations:

• Demonstrated that the offshore of Namibia is an oil-prone province, not a gas province, and that it is very similar to the oil-prone offshore basins in other parts of the South Atlantic
• Established that there are three potential oil source intervals in the Namibian offshore, and that they contain enough organic material to generate the volumes of petroleum needed to fill the reservoirs
• Verified that these source intervals are mature enough (have been heated enough) to have generated the needed volumes of oil, but are not yet generating gas
• Showed that there are pathways for migration of the generated petroleum to the reservoirs, and that the migration occurred after the reservoirs and seals were in place.

The leads/prospects identified have largely been confirmed on newly acquired/purchased 2D data and newly acquired/processed 3D data. Newer data with better acquisition parameters and processing flow generally improve prospect/lead imaging. The reason why HRT has spent $80 million acquiring and processing over 9,000 sq km (3,475 sq mi) of 3D seismic data is to reduce risk, confirm existing leads/prospects, help to generate a robust prospect inventory, and high-grade the best opportunities. We anticipate that the cost of acquisition and processing of better seismic data will likely save us the cost of a future dry hole, which could be many multiples of 3D seismic data acquisition/processing costs. A new resource study is planned for 3Q 2012.

Offshore: Have you already started drilling? If not, when do you expect to start and where? Also, are the reserves calculated at 11 Bbbl in Namibia the result of drilling? Please identify the area you are referring to.

Peres: No, we have not started drilling yet. We anticipate that we will begin execution of our planned drilling campaign in 4Q 2012. HRT recognizes promising prospects with significant resource potential within each of its operated concessions. A decision on where the first well will be drilled will be forthcoming after contracting a rig. This information will be released as we get closer to the spud date.

HRT would more accurately describe these hydrocarbons as resources, not reserves, because we have yet to drill wells in offshore Namibia. SPE defines "resources" as either "contingent," which are potentially recoverable from known accumulations, but not yet considered mature enough for commercial development…" or "prospective, potentially recoverable from undiscovered accumulations by application of future development projects."

The information HRT provides is based on resource certification by DeGoyler & McNaughton. HRT holds working interest in five offshore Namibia concessions including, from North to South, PEL 17, PEL 23, PEL 24, PEL 28, and PEL 22. The resources occur within the HRT concessions.

Offshore: Please develop the idea that the Namibian offshore basin is mainly a light oil huge frontier of exploration, instead of gas-prone frontier.

Peres: Offshore Namibia has been characterized as a gas frontier because the only significant discovery there is the Kudu gas field in the Orange basin; also the Ibhubesi gas field discovered in the South African sector of the same basin corroborates the initial model. In addition, early analyses of source rock samples appear to indicate that only gas-prone organic matter had been deposited. However, even though the Namibian margin was regarded as a gas province, it was not clear why it should be so different from the other basins on the margins of West Africa and South America, which are predominantly oil provinces.

Recently, more detailed and advanced analyses of the source rock samples, oil shows, produced condensates and gases, and the integration of these data into the paleo-climatic, paleo-geographic, and sequence stratigraphic framework of the basins show that occurrences of oil-generative source rocks in the basins of offshore Namibia are similar to those in the other basins in the South Atlantic and that the principle organic-rich intervals were originally oil-generative, rather than gas-generative. Also, detailed studies of natural oil-seep detection through the use of satellite data confirm the presence of an active oil-producing system in the Namibian offshore.

Three oil-generative source intervals have been identified: a) Hauterivian-Barremian syn-rift lacustrine sediments; b) Barremian-Aptian rift-to-drift ("sag") transitional marine sediments; and c) Cenomanian-Turonian marine sediments associated with oceanic anoxic events. These intervals were deposited under conditions very similar to those in the marginal basins in the South Atlantic in Brazil and West Africa. The discovery of gas in the Namibian offshore is the result wells being drilled in the areas of the Orange basin where the potential sources are very deep and placed in a very hot conditions (> 160°C), and so are now over-mature and generating gas. The effects of deep burial are exacerbated by the high geothermal gradients in the area, which make the sediment column hotter than it would otherwise be. However, the occurrence of oils and oil shows from marine and syn-rift source rocks, as well as detailed modeling of source rock maturity and petroleum generation show that in many areas of offshore Namibia, away from the thick sediment pile in the Orange basin, one or more of these sources has been and is still generating oil, not gas.

Offshore: Do you have an estimate for first oil?

Peres: Assuming HRT has a late 2012/early 2013 oil discovery that is followed by successful appraisal and test later in the year, it is reasonable to assume first production could begin in 2016 or 2017.

The author

Peter Howard Wertheim is Offshore's Contributing Editor based in Rio de Janeiro and can be reached at: [email protected].