Brazil is discovering billions of barrels of presalt oil at a dizzying pace, becoming an oil powerhouse and attracting international attention. Potential reserves estimates for the string of Brazilian presalt oil discoveries range from 50 to 100 Bbbl. The country’s proved reserves as of December 2010 stood at 15,986 Bboe.

Petrobras president Jos? Sergio Gabrielli says Brazil is working to become the fifth-largest oil producer in the world. Petrobras plans to more than double daily output to 5.7 MMbbl by 2020.

The company will spend US $220 billion through 2014 executing the world’s largest oil-industry investment plan. In 2011, $4 billion will be spent in the largest exploration campaign in the company’s history, which includes 162 wells, twice the average number of drilling projects over the last few years. In fact, the boom in Brazil’s offshore oil industry began in the 1970s thanks to huge discoveries of turbidite reservoirs (post-salt) in the Campos Basin offshore Rio de Janeiro.

Today, the Campos Basin produces approximately 80% of Brazil’s output, including 50% of the country’s natural gas. Unfortunately, the Campos Basin’s post-salt crude is heavy and is declining. On the giant Marlim field, which has been producing for 20 years, production declined to less than 300,000 b/d in 2010 from 645,000 b/d in 2002. As these fields mature, the basin is gaining a second lease on life with new presalt light oil discoveries.

The Tupi field holds approximately 5 to 8 Bboe of reserves. Iara holds approximately 3 to 4 Bboe. (Source: Agência Petrobras de Notícias)

Key players in the carbonate

The Tupi field discovered by the consortium operated by Petrobras (65%), BG Group (25%), and Petrogal/ Galp (10%) in the Santos Basin in October 2006 set the wheels in motion for what now is a huge prospect for development that is expected to transform the country into an oil-producing giant. Because Brazilian law requires oil fields be named after a fish, the field was renamed Lula (squid) in 2010.

The largest hydrocarbon find in the world since 2000, Lula, which lies 155 miles (250 km) from the coast of Rio de Janeiro, holds estimated recoverable reserves of 5 to 8 Bboe. Eleven exploratory and development wells have been drilled to date.

To achieve the 100,000 b/d target for the first phase of the Lula Pilot project, there will be six or seven producers, one gas injector, one water injector, and one water alternating gas (WAG) injector. Eventually, there will be nine producing wells, one gas injector, two WAG injectors, and three water injectors connected to the Cidade de Angra dos Reis floating production, storage, and offloading vessel (FPSO) through individual flowlines.

Today, the RJS-660 and RJS-665 wells are producing around 15,000 b/d, although the potential of RJS-660 is estimated at more than 20,000 b/d. Production is constrained due to the impossibility of flaring all of the asso- ciated gas. All associated gas that is not used to improve oil recovery is sent to the Mexilh?o platform via an 18-in. diameter, 134-mile (216-km) gas pipeline called Tupi-Mexilh?o.

From the platform, gas is transferred through another gas pipeline to the Monteiro Lobato gas treatment unit, also known as UTGCA, in Caraguatatuba in S?o Paulo State. There, it will be processed, compressed, then delivered to the Caraguatatuba-Taubat? onshore gas pipeline (GASTAU) which will be interconnected with the southeast transportation pipeline network.

This route will be in place in 2011 and will be able to evacuate up to 10 MMcm of gas from presalt projects in 2013. Additional routes for gas from presalt fields are under study. These include a new gas pipeline to Cabiunas, in Rio de Janeiro, and the use of floating LNG.

There are two wells planned for Cernambi field (formerly Iracema) in BM-S-11 block. One is being drilled, and work on another is expected to start in 2Q 2011.

Petrobras has filed the Declaration of Commerciality with the Ag?ncia Nacional do Petr?leo, G?s Natural, e Biocombust?veis (ANP) for the accumulations of light oil and gas in the Lula and Cernambi areas.

Two wells have been drilled in the Iara exploratory area in the northern part of BM-S-11 block. They are targeting the same formation as the wells on Cernambi at 18,045 to 19,685 ft (5,500 to 6,000 m) total vertical depth subsea. Evaluation activity will continue on Iara in line with the ANP-approved appraisal plan.

Franco, a field northeast of Iara, is considered the second-largest find in the presalt, with an estimated 4.5 Bbbl of reserves. The single nonproducing well in this area was drilled as part of the government’s plan to evaluate presalt areas before launching new bid rounds.

Two wells have been drilled in the Guar? exploratory area in Block BM-S-09, and two more are under way. The first two wells are producing via the Dynamic Producer FPSO. An additional four wells have been drilled in the Carioca exploratory area, also in Block BM-S-09. And one well has been drilled in the J?piter exploratory area in Block BM-S-24, with another planned for later this year.

In February 2011, Petrobras announced its latest Santos Basin presalt discovery in Block BM-S-10. The Macuna?ma well was drilled in 7,001 ft (2,134 m) water depth in the 1-RJS -617D (Parati) assessment area.

In early June, Petrobras plans to begin producing 35,000 b/d from the Urugua and Tambau fields, also in the Santos Basin.

Recent activity

Petrobras’ presalt E&P department reported that an extended well test (EWT) of a presalt reservoir called Tracaj?, in the Marlim Leste field in the Campos Basin, began in February 2010. An oil reservoir was discovered with well 6-MLL-70 at 14,573 ft (4,442 m) depth in September 2010.

According to Petrobras, the purpose of the EWT in the 6-MLL-70 well is to study the reservoir and design the area’s production development project. Last December, Petrobras began a similar test at an accumulation known as Carimb? in the presalt layer of the Caratinga field concession west of South Marlim field.

Recently, Petrobras completed two new wells in the presalt layer north of the Campos Basin offshore Esp?rito Santo State, proving a light oil (30? API) discovery in Parque das Baleias (Whale Park). The recoverable volume of the discoveries made in the presalt reservoirs of the Baleia Franca, Baleia Azul, and Jubarte heavy oil fields is estimated between 1.5 and 2 Bboe. The excellent results achieved by these two wells led Petrobras to expedite studies to accelerate presalt production in the basin.

Wells 6-BFR-1-ESS and 6-BAZ-1DB-ESS, drilled a few kilometers from the two presalt wells, discovered reserves under a layer of approximately 2,297 ft (700 m) of salt in water depths ranging from 4,423 to 4,678 ft (1,348 to 1,426 m). The reservoirs are 13,780 to 15,748 ft (4,200 to 4,800 m) below sea level and have oil-bearing porous thicknesses of 623 and 984 ft (190 and 300 m), proving the major potential of the discoveries.

So far, six presalt wells have been drilled and all have hit oil and gas. These new discoveries have pushed the total estimated volume of oil in the Parque das Baleias area to 3.5 Bboe. Petrobras also is preparing to bring the nearby Cachalote field onstream where production is expected to reach 100,000 boe/d this year. By 2015, the company expects Parque das Baleias to produce between 400,000 and 500,000 boe/d with presalt reserves making up approximately 40% of the increase.

Not all of Brazil’s latest significant discoveries have been in the presalt. At year-end 2010, Petrobras announced a post-salt light oil discovery Esp?rito Santo Basin, the third-largest oil and gas-producing basin in Brazil. Drilled to a total depth of 6,988 ft (2,130 m), the 1-BRSA-882-ESS well, informally known as Indra, lies about 87 miles (140 km) offshore Vit?ria, the capital of Esp?rito Santo State.

Estimates place the field’s potential at 300 MMbbl of oil.

Technology, logistics

When Petrobras began drilling in the presalt, there were many skeptics because of the enormous technology challenges. Petrobras continues to fund R&D efforts through its world-class R&D center, Centro de Pesquisa e Desenvolvimento Leopoldo A Miguez de Mello (Cenpes).

The Mature Fields Recovery Enhancement Program at Cenpes reports that, on average, the oil recovery factor is 35% in mature fields that have reached their production peak and have gone into decline. With such an enormous volume of reserves at stake, efforts are targeting enhanced oil recovery for mature fields. The Advanced Oil Recovery Technology Program at Cenpes is working on technology that it hopes will make possible a recovery factor of 50%.

Production is one major challenge; logistics is another. “In the presalt discoveries, we have two kinds of logistical problems,” Gabrielli explained at a press conference. “The first is about people, which is a problem of distance. In the Campos Basin, currently our main producing area, we transport more than 60,000 people to the platforms 150 km (93 miles) offshore by helicopter. But the presalt clusters in the Santos Basin can be 300 km (186 miles) away, too far for large-scale helicopter transportation.”

One solution for improving transportation is to build offshore platforms midway between the coast and the presalt discoveries to serve as logistical hubs with sleeping quarters so workers arriving by boat can be distributed by helicopter to the operating rigs and platforms after overnight stays on the logistical hub.

Because supply delivery is an issue as well, additional platforms could be dedicated to materials transfer. “You need transportation of chemicals, machines, plus electricity,” Gabrielli said. “We probably will have specialized platforms dedicated to generating electricity and others to mix chemicals for drilling fluids.”

Meanwhile, Petrobras is working to reduce the number of people working on the platforms by increasing the level of automation in the field.

The Cidade de S?o Vicente FPSO recently was moved to the northeast side of the Lula field in the Santos Basin and is producing 15,000 b/d. Production capacity on the FPSO is 30,000 b/d of oil and 1 Mcm/d of gas. The long duration test will collect technical information for the development of the reservoirs in the basin. The information will define the development model for the Tupi area as well as for other presalt accumulations in the sedimentary basin. (Image courtesy of Agência Petrobras de Notícias)

One Cenpes initiative to address this challenge is to develop automated processing plants to separate oil, gas, and water on the seabed. “Our target for the next 10 years is to not need production platforms,” Carlos Tadeu Fraga, director of Cenpes, told the business newspaper Valor Econ?mico.

Cenpes envisages processing units capable of working at 6,562 ft (2,000 m) water depth. Remotely monitored subsea electrical generators would power the units tasked with pumping oil and gas through pipelines that would move production flow to gathering stations and terminals on the coast.

A more immediate goal, according to information provided by Petrobras’ presalt E&P department, is to substantially reduce drilling and completion times and to optimize material specifications for wells. Effective use of the most modern rig designs will be important in achieving this objective, as will improved bit designs.

Riser qualification also will be critical. Flexible riser qualifications for production or gas and water injection are under way. Also crucial will be guidelines for installing, monitoring, and operating uncoupled riser systems, as well as flow assurance, considering wax deposition risks.

So far, the experience in presalt operations suggests that technologies also should allow the predictability of fluids distribution (lateral and vertical variation), including contaminants.

This must be supported by reservoir quality predictability based on high-resolution seismic, special seismic processing, velocity seismic profiles, well logging (nuclear magnetic resonance and image logs), well cores, lateral samples, fluid sampling, drillstem tests, long duration tests, and integrated geological modeling (including the reconstruction of the depositional environment).

Reservoir management will be vital as well and will have to include reservoir monitoring through production logs and 4-D seismic; injection optimization on a reservoir basis, including the use of intelligent completion devices; controlling the injection front by designing the drainage plan to reduce the chance of fluid channeling through high-permeability layers or conductive faults; mitigating hydrate potential in satellite injectors; and water injectivity.

One technology that likely will be put to work on the presalt fields is subsea gas processing that will allow COseparation from the gas stream and reinjection in the reservoir. Reportedly, a hub concept is being considered in which input from neighboring production units would be sent to a single location for processing. The hub platform would separate the COstream, which would be reinjected into the reservoir, and send hydrocarbons on to market through gas pipelines.

Petrobras foresees enormous expansion over the life of the presalt fields and is investing over the long term in technologies that will help the company extract the most value from its vast reserves.