Upstream in Brazil

Galp is present in several projects in Brazil spanning from the exploration to production phases.

Overview

Present since 1999 in Brazil, Galp is involved in various projects in the country in different phases of exploration, appraisal, development and production.

Galp's offshore projects in Brazil include the stakes in the prolific Santos basin, namely in the Tupi and Iracema project. 

Location of projects in Brazil

Get to know the location of the Upstream projects in Brazil.

Santos Basin

Along the Brazilian coast, Galp is present in four ultra-deep water areas since 2000, in the so-called Santos basin pre-salt cluster.

  • BM-S-11/11A
  • Greater Bacalhau (ex-Carcará)
  • BM-S-24
  • Uirapuru

The discoveries made have positioned this basin as a world class province which holds the largest known accumulation of oil and natural gas in ultra-deep waters.

Block BM-S-11/11A

Offshore

This block includes the projects:

  • Tupi and Iracema;
  • Berbigão/Sururu/Atapu.

Get to know in more detail block BM-S-11/11A.

BM-S-11 - Tupi and Iracema

Consortium: Galp (9.209% in Tupi and 10% in Iracema, through Petrogal Brasil), Petrobras (Operator, 67.216% in Tupi and 65% in Iracema), Shell (23.024% in Tupi and 25% in Iracema) and PPSA (0.551% in Tupi)

Area: 2,297 km²

Type: Ultra-deep waters

Water depth: 2,000 - 2,500 metres

2020
2019
2018
2017
2016
2010
2009
2007
2006
2001
2000

The Tupi and Iracema fields, located in the Brazilian pre-salt of the Santos Basin, reached the production plateau of the initial development phase after the completion of the floating production storage and offloading unit (FPSO) ramp-up in the Tupi North area in 2020. During the last 10 years, these fields have surpassed the historic 2 bn boe production mark, confirming their extraordinary characteristics and the scale of the reservoir.

In October, the partners agreed on the preparation of an updated Development Plan for the Tupi and Iracema fields, in tandem with the sale of unit P-71. This plan aims to identify additional development projects resilient to low oil prices and will include evaluations for a potential field life extension request.

The ninth FPSO and the third replicant unit, P-67, started production in February in the Tupi North area. This marks the conclusion of the deployment of the production units considered under the first development phase of these top tier projects.

In March, ANP approved the Unitisation Agreement related with the Tupi accumulation and submitted by the BM-S-11 consortium. The agreement establishes the tract participation each party will hold on the unitised area. The Iracema accumulation is not subject to a unitisation process and therefore interests in the area will remain in line with the BM-S-11 consortium composition.

The partners performed an extended well test (EWT) in Tupi West and the results are expected to contribute to the extensive knowledge of the area.  

 

The eight FPSO and the second replicant unit, P-69, reached first oil in October in the Tupi Extreme South area.

Performance of an EWT in the Tupi West area, through a long-distance tie-back to FPSO #1

The seventh FPSO and first replicant unit started production, marking the beginning of a new stage in the BM-S-11 project.

Six out of the twelve development areas considered in block BM-S-11 were already in production.

The Tupi and Iracema projects started commercial production through the FPSO Cidade Angra dos Reis (#1), just four years after discovery.

The first development phase of the Tupi and Iracema projects was characterised by the completion of the first of the five EWTs (Extended Well Tests), proving the excellent productivity of the wells (c. 30 kbpd) and the quality of the carbonate reservoirs..

The Tupi South well was drilled and the extension of the Tupi field was confirmed, having been proven the existence of light oil with a density of 28º API.

The consortium drilled the exploration well Tupi-1 and discovered the Tupi field, today known as Tupi, one of the largest oil fields in Brazil’s pre-salt.

The exploratory activity in the area begun, with a 22,500 km² 3D seismic survey being carried out.

June

Block BM-S-11 was awarded to the consortium in the pre-salt’s second Round.

BM-S-11A - Berbigão/Sururu/Atapu

Consortium: Galp (10% in Berbigão/Sururu and 1.7% in Atapu, through Petrogal Brasil), Petrobras (Operator, 42.5% in Berbigão/Sururu and 89.3% in Atapu), Shell (25% in Berbigão/Sururu and 4.3% in Atapu), Total (22.5% in Berbigão/Sururu and 3.8% in Atapu) and PPSA (0.9% in Atapu)

Area: 2,297 km²

Type: Ultra-deep waters

Water depth: 2,000 - 2,500 metres

2020
2019
2018
2016
2014
2008

The FPSO P-70, in the Atapu accumulation, started production in June 2020, and, by the end of 2020, had one producing well connected, from a total of eight planned, and one injector well connected, from the eight planned.

 

The first unit to develop the Berbigão and the western flank of Sururu, P-68, started production in November 2019.

ANP approved the Unitisation Agreement for the Atapu accumulation which became effective as from 1 September 2019. The agreement establishes that the BM-S-11A licence represents 17.03% of the unitised area (BM-S-11A, together with Transfer of Rights and open area), with Galp now holding a 1.70% interest
 

A six-month EWT in the Sururu Southwest area was performed through FPSO Cidade de São Vicente

Drilling of an appraisal well in Sururu led to the largest oil column in the Santos Basin pre-salt area, with 530 meters net oil pay.

The consortium members, along with Petrobras for the Transfer of Rights area, and PPSA, submitted to ANP three distinct unitisation agreements for the development of the Greater Iara project.

In the first quarter of 2018, the consortium initiated an EWT in the Sururu SW area, through the FPSO Cidade de S. Vincente.

The development plan for Atapu, Berbigão and Sururu was submitted.

Late 2016

Total and Petrobras signed an agreement which includes the sale of a 22.5% stake in the Iara area in block BM-S-11. The agreement provides that Petrobras remains the operator, with a 42.5% stake in the consortium.

The partners of block BM-S-11 carried out an EWT at Berbigão field, which proved a high productivity. The commerciality of the three accumulations referred to as Atapu, Berbigão and Sururu was declared.

The discovery of the Iara field was confirmed, with the drilling of the exploration well proving the existence of light oil with a density from 26 º to 30° API.

Greater Bacalhau

BM-S-8, Bacalhau

Consortium: Galp (20% through Petrogal Brasil), Equinor (Operator, 40%), ExxonMobil (40%)

Area: 2,297 km²

Type: Ultra-deep waters

Water depth: 2,000 - 2,500 metres

North of Bacalhau

Consortium: Galp (20% through Petrogal Brasil), Equinor (Operator, 40%), ExxonMobil (40%)

Area: 313 km²

Type: Ultra-deep waters

Water depth: 2,000 - 2,500 metres

2021
2020
2019
2018
2017
2016
2015
2011
2008
2000

During 1H2021 the consortium submitted the unitization agreement (AiP) to ANP and got the approval of the PoD (plan of development) 

In June 2021, Equinor (operator) and ExxonMobil, Petrogal Brasil and Pré-sal Petróleo SA (PPSA) have decided to develop phase one of the Bacalhau field in the Brazilian pre-salt Santos area.

In July 2020, a joint PoD for the areas was submitted to ANP.

In early 2020, FEED contracts were awarded for the Phase I of the Bacalhau project, with Modec being awarded the FPSO unit and Subsea Integration Alliance the development of subsea, umbilical, riser and flowline (SURF) equipment.The first steel-cutting ceremony took place by the end of 2020 at the shipyards of Dalian Shipbuilding Industry Corporation (DSIC), in China.

The partners spudded Carcará East, the second well located in the Carcará North block, which was followed by a DST.

ANP approved the last pending transaction in June 2019 and the partners’ stakes became aligned between the BM-S-8 license and the Bacalhau North area, with Galp holding a 20% stake in the Greater Bacalhau.

Following the Carcará North award in 2017, the partners agreed to align the equity interests across the two blocks that together comprise the Carcará discovery, with Galp holding a 20% interest in the project, whilst Equinor, the operator, and ExxonMobil a 40% stake each.

The consortium undertook a DST in the Carcará Northwest well in block BM-S-8, which revealed excellent commercial productivity potential.

The partners spudded Carcará West in September, the first well located in the Carcará North block, which was followed by a DST.

Carcará North area, to where the Carcará discovery extends, is adjacent to BM-S-8 concession.

In October, pursuant to the ANP's 2nd Production Sharing Bidding Round, Galp together with Statoil and ExxonMobil were awarded the Carcará North area.

The consortium offered a profit oil share of 67.12%, with additional commitments including the payment of a gross signature bonus of c.$930 m.

Additionally, in October, Galp, through Petrogal Brasil, has agreed with Statoil the acquisition of an additional 3% stake in BM-S-8.

Statoil acquired Petrobras’ operating stake of 66%. Activities in 2016 focused mainly on the analysis of the exploration and appraisal campaign carried out in the previous year, in order to further the knowledge of the reservoir’s characteristics and to better define the development plan for the area. The studies for defining the concept of the gas exportation system were continued.

Two wells were drilled and a Drill Stem Test (DST) was carried out, which showed excellent productivity levels of the reservoir, as well as its extension to north and west of the Carcará discovery.

A new exploration well was drilled, resulting in the Carcará discovery, with one of the largest oil columns in the pre-salt ever discovered.

The consortium made a discovery in the Bem-te-vi prospect. However, this accumulation was later abandoned, as it was considered to be non-commercial.

June 

Block BM-S-8 was awarded to the consortium in the pre-salt’s second Round.

Block BM-S-24

Consortium: Galp (20% through Petrogal Brasil), Petrobras (Operator, 80%)

Area: 1.394 km²

Type: Ultra-deep waters

Water depth: 2,000 - 2,500 metres

2021
2020
2018
2016
2015
2008
2001

Production of the unitised Sépia field started on the 23rd of August.

In August 2020, the drill stem test (DST) of the well Apollonia, was successfully completed, representing an important milestone for the progress of the Júpiter discovery. Given the high condensate to gas ratio (CGR) and the high CO2 content, this DST is considered a major technical advance.

During 2018, the Sépia unitisation agreement was approved by BM-S-24 partners and submitted to ANP. Following the submission, the consortium submitted to ANP an updated PoD.

Late 2016

Negotiation of the unitisation processes between the consortium of block BM-S-24 and Petrobras, regarding the Transfer-of-Rights area.

Júpiter

ANP approved the request for a five-year extension of the exploratory period for the Júpiter area. This extension will allow the partners of block BM-S-24 to continue the field’s technological development studies.

The studies are mainly focused on the reservoir, flow assurance, infrastructure for field development, CO2 transport, subsea separation and the different types of metallurgy to be used in the wells’ completions.

Sépia

The declaration of commerciality for the Sépia East area was submitted to ANP.

Júpiter

The discovery well was drilled in the Júpiter area, having been proven the existence of a large reserve of gas and condensates with a high CO2 content.

Sépia

During the exploratory activity of the Sépia field (Transfer-of-Rights) it was noted the extension of the Sépia field’s oil accumulation into the Sépia East area (block BM-S-24). 2015 The declaration of commerciality for the Sépia East area was submitted to ANP. 2020 Expected start of production of the unitised Sépia field.

Block BM-S-24 was awarded to the consortium in the pre-salt’s third round.

Campos Basin

Offshore

Consortium: Galp (20% through Petrogal Brasil), Shell (Operator, 40%), Chevron (40%)

Area: 701 km2

Type: Ultra-deep waters

Water depth: 2800 – 3000 metres

Number of blocks: 1

2015
2013
2005

The extension of the Pitu discovery was proven through the Pitu North well and the good permeability and porosity conditions of the well were confirmed.

The Araraúna well was drilled in BM-POT-16 and traces of oil were detected, proving the presence of hydrocarbons.

The Tango discovery was made in BM-POT-17, confirming the presence of a play in the basin. This discovery was, however, considered to be non-commercial. The Pitu well was also drilled, where good reservoir evidence was found through the samples collected.

Acquisition of block POT-M-764 in the 11th bidding round in Brazil.

Acquisition of BM-POT-16 and BM-POT-17 contracts in the seventh bidding round of oil exploration rights in Brazil.

Pernambuco - Paraiba Basin

Offshore

Consortium: Galp (20% through Petrogal Brasil), Petrobras (Operator, 80%)

Area: 1,713 km²

Type: Ultra-deep waters

Water depth: 1,000 - 2,000 metres

Number of blocks: 2

2016
2007

The consortium submitted to ANP a request for the extension of the exploratory period until 2021.

Acquisition of the two blocks in the ninth round of bidding in Brazil.

Barreirinhas Basin

Offshore

Consortium: Galp (10%), Shell (Operator, 50%), Petrobras (40%)

Area: 2,499 km²

Type: Deep water and shallow water

Number of blocks: 4

2016
2013

The consortium concluded the acquisition of 3D seismic for 1,730 km2 and continues with the interpretation of the acquired seismic, with the final processing results expected to be obtained in 2017.

ANP approved the extension of the exploration license until 2019.

Acquisition of four blocks in the Barreirinhas basin in the 11th round of bidding, three of which in deep waters (BAR-M-300, BAR-M-342 and BAR-M-344) and one in shallow waters (BAR-M-388).