Block BM-S-11/11A

Tupi and Iracema projects

Tupi and Iracema are oil fields in the Brazilian pre-salt, located in the Santos basin. They are one of the world’s largest discoveries in ultra-deep waters.

The projects are located at a water depth of approximately 2,150 metres, and are characterised by having a uniform salt layer, acting as a perfect oil and natural gas seal.

Commercial production started in 2010, only four years after the discovery, with a total of nine areas already developed.

107 kboepd average production
119 kbpd installed capacity (Galp)
150 development wells planned

Development and production activities

From the nine areas already in production through FPSO units, the first six units that started production are leased, whilst the remaining, called “replicants”, are owned by the consortium.

Applying the concept of replication of an FPSO unit allows for a high standardisation of the components and optimisation of the engineering works associated.

The development of block BM-S-11 will involve five replicant units, of which three are allocated to the Tupi and Iracema projects, more precisely to the Tupi South, Tupi Extreme South and Tupi North areas.

		Location	Start of production	Capacity
FPSO #1	Cidade de Angra dos Reis	Tupi Pilot	October 2010	100 kbpd and 5 mm³/d
FPSO #2	Cidade de Paraty	Tupi Northeast	June 2013	120 kbpd and 5 mm³/d
FPSO #3	Cidade de Mangaratiba	Iracema South	October 2014	150 kbpd and 8 mm³/d
FPSO #4	Cidade de Itaguaí	Iracema North	November 2015	150 kbpd and 8 mm³/d
FPSO #5	Cidade de Maricá	Tupi Alto	February 2016	150 kbpd and 6 mm³/d
FPSO #6	Cidade de Saquarema	Tupi Central	July 2016	150 kbpd and 6 mm³/d
FPSO #7	P-66	Tupi South	May 2017	150 kbpd and 6 mm³/d
FPSO #8	P-69	Tupi Ext. South	October 2018	150 kbpd and 6 mm³/d
FPSO #9	P-67	Tupi North	February 2019	150 kbpd and 6 mm³/d

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.

Gas export infrastructure

The development projects in the Santos basin pre-salt are designed in order to allow:

The injection of the natural gas produced in the reservoir, in order to maintain its pressure.
The export of the natural gas via pipeline to onshore, namely to supply the Brazilian domestic market.

The partners of BM-S-11 have been actively involved in the development of the natural gas export infrastructure in the Santos basin. An integrated grid of subsea pipelines is planned, with all production units expected to be connected to it.

All units allocated to the Tupi and Iracema projects are interconnected to the natural gas export grid, with the exception of FPSO #8 and FPSO #9, which started production in October 2018 and February 2019, respectively. These connections contributed to reduce the operational constraints of some of these units, enabling Galp to monetise part of the gas associated with oil production.

Opportunities to maximise value

The Tupi and Iracema projects was among the first developments in the Brazilian pre-salt cluster, facing several technical challenges::

Location in ultra-deep waters.
The large salt layer.
The reservoir’s characteristics.

As a way of overcoming these difficulties, the consortium applied innovative technologies and adapted existing ones to tackle project’s challenges.

The technological developments carried out in the pre-salt have been recognised and referenced, namely for the increased efficiency achieved in the appraisal and development operations, for the methodologies applied to reservoir management and for the results achieved in production optimisation.

Get to know some of the technologies used

Geophysical technology which, through sound wave reflection, enables Galp to characterise the geological formation in length, width and depth, verifying the variations of the reservoir’s constituting fluids throughout a given time interval.

The mapping of the spatial and temporal pressure variation of the fluid saturation in the reservoir will support the positioning of new producer and injector wells, thus contributing to a possible increase of the recovery factor of the reservoir.

The injection of water and natural gas, alternately and during certain periods of time, ensures the necessary operational flexibility in production activities and leads to an increase of the reservoir’s recovery factor.

When injected, the natural gas reduces residual oil and the viscosity, thus facilitating the displacement to the producer while simultaneously allowing more control and ensuring the maintenance of the saturation pressure.

Although there is no regulatory body in Brazil that requires the injection of CO₂, it was decided, from the beginning of the concession, to separate and inject the CO₂ from the natural gas produced, thereby reducing the operations’ ecological footprint and optimising the maintenance of the reservoir’s pressure.

Berbigão/Sururu/Atapu project

Berbigão/Sururu/Atapu is a field located in the Santos basin, in the Brazilian pre-salt, relatively close to the Tupi/Iracema project and at a water depth of over 2,000 metres. The project is composed of three different accumulations: Berbigão, Sururu and Atapu.

Exploration and appraisal activities

Through the drilling of an exploration well in 2008, it was possible to confirm the existence of hydrocarbons in the Iara area. Since then, the exploration and appraisal activities carried out by the consortium have confirmed the reservoir’s excellent potential.

The EWT carried out in the Berbigão area in 2014, from June to December, allowed Galp to deepen its knowledge about the field and revealed wells productivity levels similar, and in some cases even higher, to those obtained in the Tupi/Iracema project.

The development plan for the three distinct accumulations in the Iara area, within the BM-S-11A block and which extend to the Iara surroundings area, was submitted to ANP in 2015. In August 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. The two additional accumulations in the BM-S-11A license, Berbigão and Sururu, will also be subject to a unitisation process, and the agreements have already been submitted to ANP and are pending approval.

Regarding the declaration of commerciality of the project,it has been granted in 2016.

The production in the Berbigão and western flank of Sururu started in November 2019 through FPSO P-68, while the Atapu production started in June 2020 through FPSO P-70, the fourth and fifth replicant units deployed in the pre-salt basin.

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 Entorno de Iara area, to where the accumulations of Berbigão and Sururu and Atapu extend, was part of the Transfer-of-Rights Agreement between the Brazilian government and Petrobras, concluded in 2010.

The BM-S-11A consortium, Petrobras for the Transfer-of-Rights area and the Pré-sal Petróleo S.A. (PPSA), have already submitted the Production Individualisation Agreement. This will define the terms for the unitisation of the three fields to be developed.

In 2019, ANP approved the Unitisation Agreement for the Atapu accumulation which became effective as from 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. The two additional accumulations in the BM-S-11A license, Berbigão and Sururu are pending approval.