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Vol. 231 No. 9


Pre-salt development gathers speed

Only four years after the first discovery below the thick salt layer in Brazil’s deep water, a lengthening list of new finds indicates a long stretch of pre-salt reservoirs where three early successes may contain a total of as much as 14 billion boe.

John L. Kennedy, 21st Century Energy Advisors Inc.

Often, what is first considered a frustrating obstacle is later recognized as having an important function. So it has been with thick subsurface layers of salt. Long dreaded by explorers and drillers as hazards, salt formations are nonetheless very effective traps for oil and gas. And advancing technology has made it possible to drill and case thick salt sections safely and effectively.

There are still challenges when drilling through salt—low penetration rates, the risk of stuck pipe, potential hole-stability problems. But over the last couple of decades, accumulating experience and ever-better tools have resulted in major discoveries below thick salt layers in several regions.

Brazil’s Petrobras has made a string of deepwater pre-salt discoveries in the past few years (Fig. 1), and a significant share of the company’s current E&P capital budget—17% during the 2009–2013 plan period—will go to developing those discoveries.

 Brazilian President Luiz Inácio Lula da Silva holds up a sample of the first pre-salt oil produced at Baleia Franca Field. Courtesy of Petrobras. 

Fig. 1. Brazilian President Luiz Inácio Lula da Silva holds up a sample of the first pre-salt oil produced at Baleia Franca Field. Courtesy of Petrobras.

Petrobras discovered its first giant offshore field, Albacora, in more than 2,000 m of water in 1985. The discoveries in the Campos Basin that led Petrobras into ever deeper water typically produced heavy oil from sandstones. The basin, spreading over 100,000 sq km, gave up its first commercial field, Garoupa, in 100 m of water. Currently, the company operates 23% of the world’s deepwater production.

According to the BP Statistical Review of World Energy 2010, Brazil’s oil reserves at the end of 2009 totaled about 12.9 billion bbl; natural gas reserves were 12.7 Tcf. The country consumed about 2.4 million bpd of oil and 2 Bcfd of gas. Brazil’s offshore basins—Santos, Campos and Espírito Santo—contain 85% of the country’s oil reserves. The Campos Basin accounts for 80% of current production, but the Santos Basin and its pre-salt prospects are the “new exploratory frontier.”1


Even at this early stage, with data from only a few wells, indications are that pre-salt discoveries could more than double Brazil’s recoverable oil and gas reserves. According to Petrobras’ 2009–2013 Strategic Plan, pre-salt output could be the biggest source of domestic production growth, adding 1.24 million bpd between 2013 and 2020. “Development of the Santos Basin subsalt play will drive long term production growth,” the strategic report states. It also states that Brazil’s deepwater and ultra-deepwater production can be developed at a “relatively low cost” of about US$60/bbl.

Most of Brazil’s current crude oil production is heavier grades from its deepwater fields; Marlim, a main source, produces 19.6°API oil, for example. But as more pre-salt production comes onstream, heavy oil’s share of the country’s output will drop dramatically. The Santos Basin pre-salt discoveries have uncovered large reserves of light oil—28–30°API—with high gas content.

The Santos Basin is the largest offshore sedimentary basin in Brazil. The area currently under concession is about 41,000 sq km, and the area with Petrobras interest is about 35,000 sq km. About half of the explored area is in water depths surpassing 1,500 m. Petrobras considers the total area of the pre-salt province to be about 112,000 sq km. Areas involved in prospective pre-salt blocks are large; Tupi alone comprises 2,000 sq km, compared with the 150-sq-mi extent of giant Marlim Field. Areas identified to date in the Santos Basin pre-salt “cluster” include Tupi, Jupiter, Iara, Carioca, Bem-Ti-Ve, Guará, Paroti, Caramba and Azulão. The first discovery, Tupi, is still the largest to date.

Three pre-salt discoveries—Tupi, Iara and Espírito Santo—have estimated recoverable reserves of 9.5–14 billion boe, according to Petrobras data. Announced recoverable resources in Tupi are 5–8 billion boe; 3–4 billion boe recoverable is the estimate for Iara. Petrobras plans call for spending $28 billion on pre-salt exploration and development during 2009–2013; total E&P spending will be $105 billion. The total capital budget during that period is expected to be $174 billion. Looking further out, the company has said it plans to spend $111 billion on pre-salt capex between 2009 and 2020—$99 billion in the Santos Basin and $12 billion in the Espírito Santo Basin.

Water depths in the pre-salt development area can exceed 2,200 m, and drilling depths can be more than 5,000 m. Initial pre-salt oil production is via FPSOs; gas is to be brought onshore via pipeline. Petrobras’ strategic plan calls for six production units in the Campos and Espírito Santo pre-salt to start up by 2014, excluding the facilities involved in extended well tests. By 2013, pre-salt production is expected to be 219,000 bopd and 250 MMcfd. Oil production in 2015 will be 582,000 bpd and by 2020 is scheduled to reach 1.815 million bpd, according to the strategic plan. At that time, gas production will be 1.40 Bcfd.

In the Espírito Santo area, where infrastructure is in place, the first pre-salt production is from the P-34 well in Jubarte Field—up to 18,000 bpd. The FPSO Seillean began producing in late 2008 as a pilot system for Cachalote Field. The FPSO Capixaba was expected to move to Cachalote/Baleia Franca this year, and the FPSO Pipa II will be part of the Baleia Azul pilot system, with first production expected in mid-2012.


The pre-salt exploration age in Brazil’s offshore could be said to have begun with well RJS-628A, drilled in 2006 in the Tupi area in 2,126 m of water by a consortium of Petrobras, BG Group and Petrogal. A 1,000-m section above the salt was followed by about 2,000 m of salt, with the carbonate reservoir just below the salt at about 5,200 m from the rig floor.

According to the US Energy Information Administration, Tupi was the largest oil find since the supergiant Kashagan Field in Kazakhstan in 2000. The Tupi well certainly was a milestone, but Petrobras’ efforts to identify the potential of this area were already underway in the 1990s, when it began assessing what might be under the Antos Basin’s massive salt layers. In 2000 and 2001, in bidding for the acreage that the National Petroleum Agency (ANP) tendered in two bidding rounds, Petrobras became operator for six of the seven blocks and partnered with Esso in the seventh. In 2001 and 2002, Petrobras conducted a large deepwater seismic acquisition program, then geophysicists and geologists worked on developing processing algorithms to make what might be beneath the 2 km of salt more visible.

The first wildcat, in the Parati area, cost $230 million and had two objectives, according to a report by José Miranda Formigli, Petrobras executive manager for pre-salt: to prove the geologic model and to practice the theories that had been developed to drill the pre-salt. In 2006, with proof of hydrocarbons in the Parati area, Petrobras started drilling other wells, which led to other discoveries. With knowledge and experience, drilling costs came down to $70–$80 million.

In general, the Tupi area is characterized by heterogeneous layered carbonates with variable reservoir quality and by salt layers with thickness to 2,000 m. Well tests indicate potential flowrates of 15,000–20,000 bopd per well. Tupi oil is light, ranging 28–30°API, with viscosity of about 1 cP. The gas/oil ratio is between 790 and 1,240 (cu ft/bbl), acid content is low, and carbon dioxide content in the associated gas is 8–18%. There is some concern regarding flow assurance due to paraffin deposition in pipes.


Much was learned from an extended well test (EWT) in Well RJS-646 in the Tupi Block that completed one year of testing in May. According to a discussion of the EWT by Formigli published on Petrobras’ website in late April, the reservoir’s behavior in the microbiolite, the carbonate from which the well produces, was substantially the same as predicted by simulations. This significantly reduces uncertainty surrounding field development. The EWT also indicated good communication with other wells in the reservoir, which bodes well for the effectiveness of planned water and water-alternating-with-gas (WAG) injection.

A planned pilot will have producing wells, water injection wells and WAG injectors, in addition to CO2 injectors. The pilot project platforms and equipment are designed to last for the entire concession period, but the pilot phase will last the first two years, according to Formigli. At first, there will be eight wells, five producers and three injectors.

This first phase of the Santos Basin pre-salt development, which is expected to extend to 2017, includes EWTs, the Tupi pilot and exploratory wells still being drilled.2 Then there will be larger pilots in Guará and in Tupi Northeast, which have similar characteristics to Tupi.

Since testing indicated that the reservoir behaved well, Petrobras boosted planned production from 100,000 bopd to 120,000 bopd, along with 180 MMcfd. It is expected that production will reach 100,000 bopd by the end of second-half 2011.

Petrobras plans to install eight FPSOs in Blocks B-MS-9 and B-MS-11. Currently, the focus is on the design of production facilities and early bidding for a few critical devices. First oil from Guará will be produced to a dynamically positioned FPSO owned by Brazilian company Petroserv. Converted in Singapore, it was scheduled to begin production in August or September. The wet Christmas tree is connected to the platform by a rigid completion riser. The unit has a plant that can process up to 20,000 bpd; it consumes gas for energy and burns the remaining gas.

Other production operations in the Tupi area will treat the produced gas and transport it through an 18-in. pipeline to the existing Mexilhão platform. A 34-in. pipeline will connect this platform to an onshore terminal in Caraguatatuba. At first, the Tupi, Guará and Tupi Northeast gas will flow through this pipeline, designed for an initial capacity of 350 MMcfd, according to Formigli.

In June, the seventh well in the Tupi area helped confirm the light oil potential in the pre-salt reservoirs of the Santos Basin and reinforced the estimate of 5–8 billion bbl of recoverable oil reserves in the area. Well 3-BRSA-821-RJS—known as Tupi Alto—is in the Tupi Evaluation Plan area in 2,111 m of water, about 275 km off the coast of Rio de Janeiro. It is 12 km northeast of the Tupi discovery well.

Tupi Alto was drilled into a higher structural position than the other wells in Tupi. Tests indicate that it tapped lighter oil (about 30°API) than the average found in the other area wells.

Earlier Tupi area wells include appraisal well 3-RJS-666, designed to test the outer limits of the Tupi reservoir. It confirmed the presence of hydrocarbons, according to consortium partner BG Group. The well is 12.5 km north of the original Tupi discovery well in 2,115 m of water.

Late last year, another well, Tupi Northeast 3-RJS-662A, also encountered pre-salt hydrocarbons. The well, 18 km northeast of the Tupi discovery well, penetrated a 250-m-thick carbonate reservoir, according to BG Group. This March, well tests indicated potential for 30,000-bpd output of 28°API oil.

The consortium formed by Petrobras (65%, operator), BG Group (25%) and Galp Energia (10%) to explore Block BM-S-11 will continue to execute the evaluation plan approved by ANP and expects the field to be declared commercial by late this year.


In August 2008, BG Group announced the discovery of a thick reservoir section with excellent porosity at Iara Field in the BM-S-11 appraisal area of the Santos Basin. The well is in 2,230 m of water about 230 km from the coast. Late last year, a formation test on Iara well 1-BRSA-618-RJS confirmed estimated recoverable reserves in Iara of 3–4 billion bbl of light oil and natural gas, according to BG Group.

Iara was the third well to encounter hydrocarbons within the BM-S-11 concession area, following the Tupi discovery and Tupi Sul, drilled in late 2007. Petrobras plans to drill appraisal wells and conduct extended well tests through 2011. Production by FPSO is set for 2014. The consortium of Petrobras, BG Group and Galp will continue exploration and appraisal of the field in accordance with the evaluation plan approved by ANP.


Though Tupi has led the pre-salt revolution in Brazil’s deep water, other wells have contributed to the momentum. In July, Petrobras produced first oil from the pre-salt layer of Baleia Franca Field in the Campos Basin. Discovered in late 2008, it is “the first permanent commercial production from the Brazilian pre-salt layer, which already uses materials that were adapted and prepared to meet the specific needs involved in producing oil in the pre-salt,” according to Petrobras.

Production from the Baleia Franca pre-salt well is expected to peak at 20,000 bpd of 29°API oil later this year. The well, 6-BFR-1-ESS, produces via the FPSO Capixaba, Fig. 2. The process plant aboard the platform has been adapted to fit the needs of the pre-salt production from fields in the Parque das Baleias complex.

 The FPSO Capixaba’s process plant is designed to fit the needs of pre-salt production from the Parque das Baleias complex. Courtesy of Petrobras. 

Fig. 2. The FPSO Capixaba’s process plant is designed to fit the needs of pre-salt production from the Parque das Baleias complex. Courtesy of Petrobras.

The FPSO Capixaba is part of the development plan for Cachalote and Baleia Franca Fields. It has been producing in Cachalote’s pre-salt layer from well 7-CHT-5HA-7-ESS, 5 km from Baleia Franca, and from well 7-CHT-7HP-ESS. By the end of the year, Petrobras expects to connect the platform to a total of nine wells. There will be three producing and two injection wells in Cachalote, and three producing wells—two of which are in the pre-salt layer—and one injector in Baleia Franca. Production is scheduled to peak in December 2010 at 100,000 bopd and 48 MMcfd.

The FPSO has a production capacity of 100,000 bpd, gas compression capacity of 110 MMcfd and storage capacity of 1.6 million bbl. Water injection capacity is 140,000 bpd.


Not all pre-salt potential is in virgin pre-salt territory. A recent well found a new reservoir below the sandstone layer producer in Albacora Leste Field’s concession area in the Campos Basin. Well 6-ABL-57D-RJS, 130 km off the coast of Rio de Janeiro, is in 1,956 m of water and was drilled to a total depth of 4,536 m. Petrobras plans more drilling to assess the productivity of the light oil reservoirs and the possibility of using the existing production and offloading infrastructure. Albacora Leste is operated by Petrobras (90%) and developed in partnership with Repsol (10%).

Recently, Petrobras also announced a light oil discovery in the pre-salt layer in the Marlim Field production concession in the Campos Basin in 648 m of water, Fig. 3. The Brava prospect well 6-MRL-199D-RJS found carbonate reservoirs at a depth of 4,460 m. The well encountered about 1,000 m of salt. Petrobras estimates potential recoverable reserves at about 380 million boe. Because the discovery is only 4.5 km from existing platform P-27, part of the infrastructure for Marlim and Voador Fields, field development cost could be reduced. An assessment plan for the field will be submitted to ANP soon.

 A well in the Marlim Field concession found a new accumulation of 29°API oil in the pre-salt layer. Courtesy of Petrobras. 

Fig. 3. A well in the Marlim Field concession found a new accumulation of 29°API oil in the pre-salt layer. Courtesy of Petrobras.

Earlier this year, Petrobras announced two discoveries in the Campos Basin’s post- and pre-salt areas with well 6-CRT-43-RJS, known as Carimbé. The discoveries are in Caratinga Field in 1,027 m of water, about 106 km from shore. The post-salt reservoirs are 3,950 m below the seabed and contain an estimated recoverable reserve of about 105 million boe. The pre-salt reservoir, found in the same well at 4,275 m, appears to be an extension of the accumulation discovered previously by well BR-63A 6-RJS in the Barracuda Field area, announced early this year. The new find could contain recoverable reserves of 40 million boe; if the “extension” assumption is confirmed, total recoverable reserves could be 360 million boe.

The new well could be connected to the P-48 platform that now serves Caratinga Field, making use of existing production and offloading infrastructure. An evaluation plan for these accumulations will soon be submitted to ANP.

Late last year, well 4-SPS-66C, known as Abare West, found oil and gas in a separate pre-salt structure within the 1-SPS-50 evaluation plan area on BM-S-9 in the Santos Basin. The area also includes the Iguaçu well 4-BRSA-709, announced in April 2009, and Carioca discoveries announced in September 2007. Abare West is 30 km from the Iguaçu discovery, 40 km from the Carioca discovery, and 50 km to the west of the Guará discovery, well 1-BRSA-494-SPS. Abare West, in 2,163 m of water, encountered oil, gas and CO2 in pre-salt reservoir sections.

In late 2009, the consortium of Petrobras (45%, operator), BG Group (30%) and Repsol (25%) announced that the Guará discovery in the Santos Basin pre-salt holds estimated recoverable reserves of 1.1–2.0 billion boe. During a drill stem test, Guará flowed at a facilities-constrained 7,200 boepd. It is expected that a permanent production well could initially produce up to 50,000 boepd. According to BG Group, the development will use a 120,000-bpd FPSO when production begins in 2012.


In the Tupi area, drilling is complicated by the presence of different types of salt with different creep rates. But temperatures are lower than in some other areas, meaning creep rates are significantly lower. Though Petrobras’ experience indicates that wellbore closure in the salt is not fast enough to cause severe operating problems, the company considers casing collapse a main concern in the pre-salt. Concerns about well integrity are amplified in the case of deviated wells.

Production of significant CO2 volumes will require special materials. Other issues are increasing penetration rates to reduce drilling cost and developing stimulation techniques appropriate for high-volume wells in heterogeneous reservoirs.

Petrobras is focusing its pre-salt R&D on several key areas, including:3

• Well technology, including casing stability, well cost and productivity
• Complex reservoirs that are vertically heterogeneous and cover large areas
• Wettability concerns that can affect the performance of waterflooding and EOR
• Wax deposition that complicates subsea design, caused by low seafloor temperatures
• Gas processing and exporting technologies to deal with high CO2 content and high gas-to-oil ratios.

Petrobras established its pre-salt technological program in 2007 to develop and disseminate technologies to incorporate reserves and to develop the production of the new pre-salt discoveries. An important goal of the project was to focus on well construction for the pre-salt section—drilling fluids, cement resistance, stimulation techniques, geomechanical model, liner drilling, well control in the salt zone, and multilaterals. It also aimed to develop geoscience toolboxes—chemical stratigraphy, core log test integration, geomechanical model and fracture distribution, pre-salt imaging and seismic attributes. And its reservoir engineering focus was to be on recovery optimization.

Development of the pre-salt area is also complicated by its long distance from shore. Tupi, for example, is about 300 km from the coast, in a harsh ocean environment.  


In addition to its own ongoing technological development efforts, Petrobras has developed partnerships with technology providers to address the unique challenges of pre-salt operations and development.

Baker Hughes is expanding its Brazil operations to support the growth of Petrobras’ activities in the Santos and Campos Basins. New construction projects include a 5,600-sq-m regional technology center in Rio de Janeiro; an expansion of existing operations bases in Macaé, including a test well for completion and artificial lift systems; and a 60,000-sq-m manufacturing plant.

Under a 2009 cooperative agreement, Baker Hughes and Petrobras will open the Rio Technology Center in 2011. Projects at the research facility will focus on reservoir characterization and modeling, drilling optimization, and completion and production technologies to lower drilling and wellbore construction costs, as well as optimize production and recovery through better reservoir understanding.

Petrobras and Halliburton have a technological cooperation agreement for pre-salt reservoir R&D. Three research projects were originally negotiated: technologies to determine contamination in bottomhole fluid samples; well production behavior simulations in the lab; and salt and CO2 formation cementation. The agreement will be in effect for three years, and can be renewed for an equal term. Petrobras said the project portfolio established by the two companies will lead to the deployment, in 2011, of the Halliburton Brazil Technologies and Solutions Center in Rio de Janeiro.

Schlumberger and the Federal University of Rio de Janeiro (UFRJ) will open this year the Brazil Research and Geoscience Center (BRGC) in Rio de Janeiro, Fig. 4. The installation will focus R&D on the challenges posed by the ultra-deepwater pre-salt. Begun late last year, the center will be partially opened in November and fully operational in February 2011, with capacity to host more than 350 employees. Activities will include pre-salt research projects, software development, seismic processing and interpretation, and a combination of labs—core, fluids, cementing and stimulation. This combination aims to deliver an optimum comprehension of reservoir behavior, with workflow of simulations and tests adapted and calibrated with real environment information. In addition to the research center, this year Schlumberger opened a new office in Santos and completed construction of one of its largest bases in the world to support deepwater operations and pre-salt development.

 Schlumberger will open its Brazil Research and Geoscience Center in Rio de Janeiro late this year. Courtesy of Schlumberger Ltd.   

Fig. 4. Schlumberger will open its Brazil Research and Geoscience Center in Rio de Janeiro late this year. Courtesy of Schlumberger Ltd. 

FMC Technologies will also build a new facility in Brazil under an agreement with the UFRJ. The Brazil Technology Center will be located on campus at UFRJ Technology Park in Rio de Janeiro, an area that FMC called “the hub of the country’s future oil and gas technology developments.” The building will contain engineering offices, technical training and design areas, research and development laboratories, and the capability for full-scale prototype integration and testing of subsea systems. Construction began in July and the facility is expected to open in the first half of 2011. wo-box_blue.gif


 1 Carmanatti, M., Dias, J. L. B. and Wolff, “From turbidites to carbonates: breaking paradigms in deep waters,” OTC 20124 presented at the Offshore Technology Conference (OTC), Houston, May 4–7, 2009.
 2 Filho, F. J. M., Pinto, A. C. C. and A. S. de Ameida, “Santos Basin’s pre-salt reservoirs development: The way ahead,” OTC 19953 presented at OTC, Houston, May 4–7, 2009.
 3 Beltrão, R. L. C., Sombra, C. L., Lage, A. C. V. M., Fagundes Netto, J. R. and C. C. D. Henriques, “Challenges and new technologies for the development of the pre-salt cluster, Santos Basin, Brazil,” OTC 19880 presented at OTC, Houston, May 4–7, 2009.


John Kennedy

John Kennedy, president of 21st Century Energy Advisors Inc., analyzes oil and gas technology, markets and issues for a variety of clients. He has an engineering degree and has covered global petroleum activity for several decades.







-- Edited by admin on Wednesday 28th of March 2012 06:51:53 PM



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