GEO ExPro

Monsters of the Deep

Hidden by a thick veil of salt and once thought too deep for liquid hydrocarbons, recent deep water discoveries off the southeastern Brazilian coast could be the largest in the past 30 years.
This article appeared in Vol. 5, No. 5 - 2008

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Close up of the Jupiter discovery showing the sub-salt play consisting of microbiological limestone (stromatolithes) and possible coquina reservoirs interbedded with source rock shale. The trap is formed by the wedge out of reservoirs against old structural highs. © HRT and CGGVeritas Petrobras, the Brazilian state owned oil company, has announced nine recent discoveries in the ultra-deep water play 250 km off shore in the Santos Basin. The first one was Tupi in late 2007; the Jupiter and Carioca-Sugar Loaf discoveries followed. Tupi and Jupiter are located on separate structures and are reported to contain 6 to 8 Bboe. The Carioca-Sugar Loaf discoveries, possibly two to date, are on an enormous structural high (possible exceeding 2,500 km², five times that of Tupi) about 60 km west of Tupi. The Carioca-Sugar Loaf could add more than 33 Bboe, making it the 3rd largest field ever discovered. (Editor's note: Petrobras has been careful not to put out any reserve figures at this time. Most recently, at the OTC conference in Houston, their Exploration and Production Director, Guilherme Estrella said "We will not present the results in terms of the oil volumes. We are still in a discovery, evaluation phase.)"

  • The current exploration focus of the ultra-deep, sub-salt play extends over 800 km (200 km wide) from the southern end of the Santos Basin, through the Campos Basin, and north into the Espirito Santo Basin. This focus could spread north to other eastern margin basins. ©HRTrnttttThe recent sub-salt discoveries in the Santos Basin could have a combined 60 Bboe. ©HRT



These Santos Basin discoveries point the way to new exploration opportunities along Brazil's coast and to basins across the Atlantic. The exploration frontier could encompass nine different sedimentary basins along Brazil's Atlantic margin and have implications across the Atlantic in sedimentary basins along the West African coast.  

This new petroleum system has already been expanded north of the recent Santos discoveries with two ultra-deep, sub-salt discoveries in the Campos Basin. The first, near the Jubarte field, is the first sub-salt oil field to be produced. Production started on September 2, 2008 with a Long-Duration Test (LTD) that will last 6 months to a year. This test will allow companies to observe how the sub-salt oil behaves, both in the reservoir and in the platform's processing plant. Current production is around 18,000 b/d of light 30º gravity oil. The most recent discovery was announced September 30 on Anadarko's Yahoo prospect, located about 40 km northeast of the Jubarte field. The US-based independent is the first foreign company to make a major sub-salt discovery offshore Brazil. They reportedly struck at least 60 m of pay and plan to drill the well to 6,100 m total depth.  

While the Santos is the largest basin covering an area over 350,000 km², the deep, sub-salt play off Brazil's coast could involve basins totaling 770,000 km², an area larger than the entire state of Texas. The current exploration focus is in the three southernmost basins, the Santos, Campos, and Espirito Santo (sometimes referred as the Greater Campos Basin), covering a length of over 800 km, 200 km wide.

Seismic line and map of the sub-salt reservoirs across the Jupiter discovery, offshore Brazil. © HRT and CGGVeritas

Going Offshore


Well log through the sub-salt section down to basalt basement. The Lower Cretaceous consists of a nonmarine, syn-rift megasequence. The Lagoa Feia Formation (Campos Basin and equivalents) is made up of a series of interbedded sandstone, coquina, and organic-rich shale. ©HRT Brazil's first offshore field was discovered in the shallow waters off the northeast coast in 1969. From these early beginnings, new offshore discoveries followed to the south in the Campos Basin. Exploration drilling started here in 1971 and the first oil was produced in 1977 from the Enchova field (for more information leading up to the recent sub-salt discoveries see GEO ExPro v.5 no. 4 pp. 76-80). From the 1970's through the early 1990's, exploration has remained concentrated there and accounts for about 80% of Brazil's oil production. Over 70 accumulations including seven giant oil fields have been found.  

Most production is from Tertiary and Upper Cretaceous turbidite sandstone reservoirs that were deposited off the shelf in deep water. The petroleum system includes Early Cretaceous source rocks that are part of a nonmarine rift sequence. The lacustrine sedimentary rocks of the Lagoa Feia Formation lie below a sequence of conglomerates and carbonates followed by a thick evaporite section consisting of halite and anhydrite. Listric faults and salt windows provided upward migration routes into the reservoirs.

Sub-Salt Ignored


The Tupi discovery is 300 km off shore in 2,200 km water depth. Potential flow rates are 20,000 bopd of 28 to 30º API gravity oil. Nearly 2,000 m of salt overlay the 76 m of oil saturated reservoir rocks. Massive halite and bedded evaporites are seen clearly on this line. Most of Brazil's deepwater, sub-salt basins remain unexplored. This is a little surprising as Petrobras is the world's leader in sub-sea completions and has a long history of offshore production and innovation. In addition, early exploration in the Campos Basin targeted shallow water, pre-salt reservoirs. Several large oil fields were discovered in the late 70's to early 80's in sub-salt fractured basalts, sandstones, and coquinas, with coquinas being the primary reservoir. However, with the discovery of super giant fields in post-salt, Upper Cretaceous and Tertiary large scale, turbidite sandstones, the sub-salt system was largely ignored until 2004.

"It was generally believed by Petrobras geoscientists that the sub-salt rocks were too compacted to be good reservoirs," says Dr, Marcio Mello, President of High Resolution Technology and Petroleum (HRT). "The sub-salt play also faced many challenges. First of all, the salt layer is very complex. Properly imaging reservoir targets below it was improving but still very difficult. Recent 3-D petroleum system modeling suggested deep reservoirs with a much higher potential than previously predicted. Second, the salt layer can be mechanically unstable making drilling very expensive. Beneath the salt, wells can lose circulation and encounter basalts with high temperatures and pressures a major concern. A normal offshore well costs $35 million; sub-salt wells cost between $100 million to $150 million."  

Exploration in the Santos Basin prior to the sub-salt discoveries had found just two productive oil fields. Most of 115 exploratory were either dry or noncommercial. Over 1,100 wells have been drilled in the smaller Campos Basin. Using the Campos Basin as a model, exploration focused on relatively shallow post-salt clastic objectives. These reservoirs turned out to be much poorer than correlative intervals in the Campos Basin.  

Source rocks for the petroleum system are Lower Cretaceous lacustrine shales of the sub-salt Guaratiba Formation, equivalent to Lagoa Feia Formation found in the Campos Basin.

Looking Deeper

Due to poor exploration results from the Santos Basin and a lack of large prospects in the post-salt in the Campos Basin, Petrobras and other exploration companies were forced to look deeper. Companies started looking for new giant oil and gas accumulations into the new, deep water, sub-salt frontier at depths exceeding 6,000 m. The discovery of the super giant Tupi field two years ago confirmed the ultra deep potential.  

"We have known for a long time that 98% of the oil and gas produced in the greater Campos Basin was sourced by the pre-salt sag and rift lacustrine source rocks. This system extends more 2,000 km north from the Santos Basin," says Dr. Mello. "These form the most important source rocks in the South Atlantic margin and have sourced oil in accumulations throughout the entire stratigraphic column in the greater Campos Basin."  

"Case histories have taught us that where overcharged source rocks occur at the base of the sedimentary sequence, large volumes of hydrocarbons are associated with deeper horizons. Our modeling has been telling us to look to the deeper reservoirs since 2002." says Marcio, ‘Mr. GO DEEP' (See GEO ExPro v. 5, no. 4, pp. 72-74). The recent discoveries confirm our early assessments."  

Source and Reservoirs

Above the basement basalts, sandstones, stromatolithes, and coquinas made out of pelecipods deposited in structural highs are important reservoirs and are interbedded with the source rocks. Porosity ranges from 12% to 30% and permeability can be over 500 md. Recent data show the presence of well sorted sandstone reservoirs with very good permeability and porosity in the pre-salt sequence of Santos Basin. Carbonates and sandstones also are important reservoirs in the lower Albian, with permeability ranging from 1 to 2 darcies and intergranular porosity as high as 35%. However, from unofficial sources, stromatolithes are the primary reservoir for all the discoveries in the Santos Basin to date.  

Seismic Stratigraphy

Dr. Marcia Karam, a geophysicist for Queiroz Galvao Oil and Gas, has used seismic data to identify the sub-salt sequences and prospective exploration areas where well and other data is lacking. Photo: Tom Smith It is important to note that the sub-salt sequences in the Santos Basin have been drilled only a few times but a large data set of both 2-D and 3-D seismic data exists over most of this huge basin.    

"The syn-rift sediments comprise important source rocks and their recognition and distribution on seismic data are an essential fact to understanding the petroleum systems of these basins," says Dr. Karam. "We have used seismic stratigraphic analysis to identify three sequences from their internal reflector patterns and external geometry to locate a prospect in the southern end of the basin that we are currently drilling with Petrobras."  

"The Early Rift Sequence (lower rift on Tupi seismic line) is compounded by volcanic rocks and characterized by parallel to subparallel reflectors, continuous and high dip angles," says Dr. Karam. "The Rift Sequence (upper rift on Tupi seismic line) is characterized by half grabens, possibly filled by coarse sediments. The main internal reflections are divergent and prograding. The final Sag Phase was deposited on an unconformity identified by 3-D data. Reflectors truncate down and onlap above. It is very important to recognize source rocks were deposited in both the Rift Sequence and the lower Sag Phase. Most of the reservoirs are located near the top of the Sag Phase and some may be interbedded with the source rocks in the both Santos and Campos Basins." (For more about rifting phases see "The Dawning of Two Continents" GEO ExPro v. 5, no. 4.)

To Production

Tests have shown that wells are capable of high production rates (exceeding 3,000 bopd) of light, 27 to 30º gravity oil. Petrobras researchers are already making plans to bring these fields on line.  

"Petrobras has taken steps in the past to bring new discoveries on line in a safe, efficient manner," explains Dr. Mauricio Werneck, at the Petrobras Research and Development Center (CENPES) and Manager of PROCAP 3000. "We started our first program to handle discoveries down to 1,000 m. Then, with the super giant discoveries in the Campos Basin that exceeded the 1,000 m water depth, we developed the PROCAP 2000 program to address these deeper water depths. We are now working on PROCAP 3000 that is aimed at exploring areas in the Gulf of Mexico and Africa, along with Chevron, that will take us to the next level of production in these ultra-deep environments."

"The new program will be closing some of our technical gaps we have now operating in this ultra-deep environment," says Dr. Werneck. "We coordinate and integrate all disciplines, working closely with geologists and reservoir engineers."  

"Production for the sub-salt discoveries will entail the standard facilities that were developed for the deep turbidite sandstone reservoirs in the Campos Basin," adds Dr. Werneck. "New to the sub-salt play are limestone reservoirs. We are in the process of gathering data with long term or extended production testing necessary for the design of facilities, well spacing, and reservoir maintenance. The extended well tests will last two years into 2010 and will involve a large number of both production and injection wells."  

When asked if he anticipates any technical problems, Dr. Werneck answered, "There will be some challenges to meet production goals, some of this will depend upon company strategy. A time line for production has not yet been established." This being said, Petrobras has already leased 80% of the world's deep water drilling rigs. Over the next 9 or 10 years, they plan to spend $5 billion to develop and hire deep water vessels. This, according to Petrobras President and CEO José Sérgio Gabrielli de Azevedo, would build another 146 ships and hire 40 deep water rigs indicating they are very serious about developing their deep water properties.  

Guilherme Estrella, the Petrobras Exploration and Production Director, concurs with Dr. Werneck saying, "We are dealing with a little-known rock, and we are investing heavily in geologist qualifications to learn more about it. We have also been investing in rock knowledge to find out more about the oil reservoir, to determine how we are going to manage this reserve using artificial production and advanced production approaches. It is likely that we will have reached a level of knowledge and technological development in the next four or five years to allow us to consider kicking production off at these accumulations.

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