South America is one of the world’s largest producers of oil, and its abundant pre-salt reserves are happy hunting grounds for prospectors and operators. GlobalData presents a snapshot of some of the key sites in the continent’s booming fossil fuel industry.
Franco, Brazil
The Franco oil field is located 130 miles (210km) south of Rio de Janeiro, offshore Brazil. It is a pre-salt, deepwater field in the Santos Basin, at a water depth of around 6,550ft (2,000m). Operator Petrobras has a 100% equity stake. According to Brazil’s energy regulator, the National Petroleum Agency (Agência Nacional do Petróleo, ANP), Franco could hold 8-12 billion barrels of oil, and could be at least as large as the giant Libra field.
The field was discovered in May 2010, when the 2-ANP-1-RJS well produced high-quality oil of 28-30°API. Following successful testing, Petrobras expects to start production in 2016.
Table 1 (opposite) shows a snapshot of the Franco field. The reservoir rock includes microbial carbonates of a sag sequence, along with limestone coquinas formed during a syn-rift sequence.
Petrobras has awarded development contracts to UTC Engenharia, Norberto Odebrecht and OAS for conversion of four very large crude carriers – P-74, P-75, P-76 and P-77 – into FPSOs.
The conversion work started in June 2011 at the Inhaúma Shipyard in Rio de Janeiro, and all four FPSOs will have a maximum production capacity of 150mbd. Petrobras will use P-74, P-75, and P-77 for production at the Franco field, and P-76 at the Franco Sul field. P-74 is expected to start production in the second half of 2016, which will also see the start of production at the Franco field. P-76 is expected to start production in the second half of 2017.
Development of the Franco field involves several challenges, including high well costs, which are estimated at around $66 million. Moreover, the wells are prone to salt creeping and hydrate formations – caused by mixing hydrocarbons with produced water at high pressure and temperature – leading to well closure, or blockages of the production system.
The field development will also involve the setup of carbon capturing or CO2 reinjection capabilities, as Brazil’s environmental constraints do not allow the venting of large quantities of CO2 into the atmosphere.
Cernambi, Brazil
The Cernambi oilfield, previously known as Iracema, is a pre-salt field located in block MS-11 in the Santos Basin, offshore Brazil. The field is located in ultra-deep waters, with depths ranging from 6,200 to 7,800ft (1,900-2,400m). The reservoir depths range from 16,000 to 20,000ft (4,900-6,100m) below sea level. The field should begin commercial production in Q4 2014. Peak production of 300,000 barrels per day (bpd) is expected to be attained by 2016.
Petrobras has a 65% stake in the Cernambi field and is the operator. BG Group and Galp Energia are stakeholders in the field, holding 25% and 10% respectively. Cernambi was awarded as part of the ANP’s concession bidding round two, held in 2000. The field was declared commercially viable in 2010, and is presently under development.
Table 2 shows a snapshot of the Cernambi oil field.Its geology is similar to that of the Lula field, both of which are located in block MS-11 of the Santos Basin.
The pre-salt reservoirs located beneath the Lula field are Aptian rocks of microbial composition, and heterogeneous carbonates. The main challenges encountered with such reservoirs are difficulties in assessing their characteristics, paleo-environment and oil migration.
The development plan for the Cernambi field includes the use of two FPSOs. The first, FPSO Cidade de Mangaratiba, will start production in 2014 in the southern area of the field; the second will start production in 2015 in the northern part. Both FPSOs will have a capacity of 150mbd. Development of the Cernambi field will involve challenges of hydrate formations, salt-creeping in wells and wax depositions in the flowlines.
Moreover, pipelines carrying liquids and gas can develop slugs due to uneven distribution of the two products, causing erratic flow behaviour.
Carabobo-1, Venezuela
The Carabobo-1 onshore oil field contains around 31 billion barrels of recoverable extra-heavy crude oil of 8° API. It is believed to be among the four largest onshore oil fields in the world.
Initial production started in 2012 at 350bpd, and a plateau of around 400mbd is thought to be sustainable from 2017 to 2057, if appropriate EOR methods are planned to be implemented by the end of primary recovery, which is forecast for 2025.
Carabobo-1 is a crude oil production asset in the Morichal field, on the Orinoco Oil Belt. The total area of the asset is about 94,641 acres. Petróleos de Venezuela (PDVSA) is the operator, with the largest equity stake in the asset at 60%. ONGC Videsh, Petronas and Repsol are the other major equity stakeholders, each with an 11% share.
Petrocarabobo is a joint venture of the equity stake holders, while PDVSA is the operator through its subsidiary Corporacion de Venezolana Petroleos.
Table 3 provides a snapshot of the Carabobo-1 asset. Carabobo-1 is located on the eastern side of central Venezuela’s Orinoco oil belt, in the Foreland Basin.
Extra-heavy crude oil lies in reservoirs of the Miocene sandstone Oficina Formation, at depths of 490-4,500ft (150-1,350m). The API gravity of the heavy oil and viscosity are in the range of 4-16° API and 2,000-8,000 centipoise (cP) respectively.
The development of the Carabobo-1 asset is divided into two parts: north and central. The former has an area of 50,162 acres, while the latter covers 44,479. Carabobo-1 development includes construction of an upgrader with a capacity of 200mbd. The construction of the upgrader started in 2012, and is expected to be complete by 2017. Once the first set of upgraders is complete, a second is planned.
The development plan of the asset may include drilling an estimated total of 99 wells by the end of 2014. Additionally, an estimated 100 development wells are expected to be drilled each year from 2015 up to 2025.
This will help to increase production rates to 400mbd by 2017, and arrest the production decline while maintaining a plateau at this rate. From 2025 onwards, an estimated 50 development wells will have to be drilled each year until 2039, to maintain an annual decline rate of 10%.
The sandstone reservoirs of the Orinoco belt have several depositional sequences that are heterogeneous in terms of fluid-flow characteristics, causing a significant reduction in recovery efficiency.
The other challenge is restricted availability of drilling rigs in Venezuela in general, which could affect the development of the asset.
In September 2013, Petronas announced its decision to leave the Carabobo-1 project as part of its strategy of abandoning exploration projects, which it considers to have marginal profits or to create losses. This could affect the asset’s development.
Castilla-Chichimene, Colombia
Castilla-Chichimene is a pairing of two fields in the Llanos Basin in Colombia, approximately 62 miles (100km) south-east of Bogota. Operator Ecopetrol has a 100% equity stake. The total crude oil recoverable reserves of the fields are quite high at 1.2 billion barrels. The fields are the leading contributors of crude production in Colombia.
Table 4 provides a snapshot of the Castilla-Chichimene project. Castilla and Chichimene are located in the north-eastern part of the Llanos Basin and produce heavy and medium-heavy crude from the San Fernando formation. The fields mostly consist of marine sediments with some terrestrial inputs. The anticlinal features of the fields are situated about nine miles (15km) east of the thrust fault in the basin. The fields mainly produce from the Guadalupe Sandstone reservoir.
Castilla and Chichimene are located close to one another, but their geologic properties differ significantly. Chichimene has a normal level oil-water contact; while in Castilla this is abnormally tilted.
The Castilla field was discovered in 1969 and produces crude of 13.5°API. The Chichimene field was discovered in 1984 and produces crude of 20°API. The crude produced from the fields is called the Castilla blend. Around 59% of this is piped to Coveñas port for exports, while the remainder is refined for local use.
Before 2000, Chevron and Ecopetrol had equal stakes in the Castilla and Chichimene fields, with Chevron as the operator. In 2000, Ecopetrol acquired Chevron’s stake and became the operator. Production from the two fields is now around 117mbd, and is expected to reach 300mbd by 2015. The plans for the fields include the drilling of 60 new wells, and a fluid disposal facility is under construction in order to manage wastewater from the Castilla field.
The pipeline transportation capacity from the Castilla and Chichimene fields was increased from 105 to 190mbd in 2013. This, however, has created a need more naphtha, which is used to dilute the crude, raising the operating expenditure, as some of the naphtha must be imported. The water-to-oil ratio of the fields is also high, and Ecopetrol needs a proper plan to handle the increasing amounts of waste water.