Changing the game

Brandishing an array of government initiatives and the allure of world-class geology, Brazil is intent on reversing recent years of decline in overall production. Changes in how business is conducted, combined with major projects going onstream and upward trending oil prices, may make this the year.

A TURNING POINT 

While Brazil’s oil production has suffered an onslaught of challenges, from maintenance and mature fields to project delays and politics, many industry observers believe 2019 will mark a positive turning point. Much of the optimism rests on pre-salt production, which has grown despite the difficulties; but conventional offshore and onshore production has dropped precipitously, and reversing that trend is vital to a sustained improvement.

“Brazil is reaching a new level of production, and that is a fact,” said Décio Oddone, director general of the Brazilian National Agency for Petroleum, Natural Gas and Biofuels (ANP). “2019 will be critical.”

IMPETUS FOR CHANGE

After a long period of production growth, recent years have not been kind to Brazil, Fig. 1. From 1.8 MMbpd in March 2013, oil production increased to a high of 2.7 MMbpd in December 2016. But five years without bidding rounds (2008-2013), as well as reduced investment, an oil price collapse and a host of other issues, took a hard toll.

Fig. 1. Many factors turn around Brazilian oil production that has declined since 2016. Chart: Knoema data services.

Between 2011 and 2017, exploratory wells drilled dropped 89% (Fig. 2); development wells fell 70% from 2015 to 2017. In November 2018, ANP reported a 5.9% output decline, to an annual average 2.5 MMbopd. In March 2019, monthly production averaged 2. 6 MMbopd.

Fig. 2. Dramatic drops in wells drilled have prompted many changes. Charts: ANP.

Production dropped in all regions except the pre-salt play. Pre-salt production in 2010 was 41,000 bopd; in 2018, it was an impressive 1.5 MMbopd. At the same time, offshore post-salt production in the Campos basin dropped 31%, Santos and Espirito Santos basins fell 41%, and the Northeast basins plummeted 61%. The onshore situation is also worrying, said ANP. Between 2012 and 2017, onshore production declined 30% and drilling fell about 80%. Marine fields produced 96% of oil and 83.7% of natural gas in Brazil.

Gas production has not suffered the same volatility as crude, and has grown steadily over the years. Total production in 2018 was 40.8 Bcm, a 1% gain over 2017, said ANP.

DOWN, NOT OUT

To counter the oil declines, the Brazilian government mounted a broad program to maximize recovery, increase reserves, and attract operators, service/supply companies, and financial institutions. The efforts include measures for more attractive contracts in bidding rounds, reductions in royalties for incremental production from mature fields, a new R&D strategy, reserve-based lending, local content changes, and divestment.

Opening the pre-salt to foreign operators is a significant change from previous rules requiring Petrobras to act as sole operator. Petrobras now has pre-emption rights to act as operator, or license the property to another operator under a production sharing agreement. The measure was passed in late 2016, to streamline development of pre-salt reservoirs and attract a higher volume of investments. To make concession contracts more attractive, Brazil has adopted single-stage exploration, set royalties for new frontiers and mature basins, reduced the minimum net equity for non-operators, and created incentives to increase investment fund participation.

New E&P policies have been issued to optimize recovery, quantify oil potential, intensify exploration, and promote proper monetization of existing reserves. Government programs include initiatives to revive onshore areas, and develop internal gas and fuel markets. Creation of an annual auction schedule, for the first time, is already showing an ability to attract investors. The four rounds carried out in 2017 under the new five-year plan exceeded expectations, said ANP. 

Divestment of non-core assets is helping Petrobras reduce debt and focus on pre-salt investments. Shallow water and onshore fields, a pipeline unit, and refineries are among assets on the block.

Changes to local content rules after the 2017 rounds are expected to unlock investment in 36 FPSO vessels and speed development through 2027, Fig. 3. The move is intended to debottleneck the domestic supply chain, by allowing FPSO hulls to be built internationally while select modules are built and integrated locally. Wood Mackenzie analysts think the change could create more than 95,000 jobs, and double royalties from $28 billion to $56 billion in the next decade.

Fig. 3. Production potential and FPSO additions. Local content rules will spur FPSO construction and speed production. Chart: ANP.

ANP expects the full scope of initiatives to increase production to 5.5 MMbopd in 10 years. Despite the pre-salt interest, much of the gain is expected to come from mature fields and basins, where there is a low average recovery rate. ANP said a 1% addition to the recovery factor would add 2.2 Bboe of new reserves and $18 billion in new investments, while noting that the potential of unconventional resources in new frontier basins is barely known.  

But Brazil’s potential is much greater than even these figures suggest, said ANP. The country has proven oil and gas reserves of 15 Bboe and produces 3.3 MMboed (including 2.6 MMbopd). Less than 5% of sedimentary areas are contracted.

THE RESOURCE

Brazil’s three E&P environments offer very different resources. Onshore operations include mature basins and new frontier basins, mostly with gas potential that is needed domestically. Production makes up about 7% of the total, with 6,994 wells producing 117,000 bopd at an average 17 bopd. 

Conventional post-salt offshore production makes up about 39% of the total. It includes all the east margin and equatorial margin areas and comprises a significant number of large, mature fields. The assets include 641wells producing 1,090,000 bopd at an average 1,632 bopd/well.

Pre-salt assets include some of the largest offshore discoveries in the last decade. Production from the play makes up 54% of the Brazilian total, with 86 wells producing 1,408,000 bopd with average production per well of 16,968 bopd.

LICENSING ROUNDS  

The licensing regime is designed to stimulate a broad scope of objectives beyond growing reserves and production. They include expanding knowledge of sedimentary basins, decentralizing the exploration investment, and providing opportunities to small- and medium-sized companies.

Properties are offered in concessions and production sharing rounds. With concessions, the winning company assumes the risk of investing and finding oil or gas. It includes an Open Acreage process that continuously offers relinquished marginal oil fields and exploration blocks that are unawarded. The blocks are onshore and offshore, and they include exploration tracts and marginal oil fields.

Production sharing involves pre-salt and other strategic areas. In deciding to conduct a bidding round, Petrobras is first offered the block as operator. If it declines, bidding ensues, with the winning company offering Brazil the largest share of production. 

Bidding under the new five-year plan has been strong. In 2017, Round 4 of marginal assets sold eight out of 10 offered areas and had the highest signing bonus in the category of mature fields. In the 14th Round, 37 exploratory fields were acquired, with the highest signing bonus ever collected in concession auctions. In the 2nd and 3rd pre-salt production sharing rounds, six out of the eight offered areas were acquired. The 2017 total translates into 2-MMbopd peak production, 15 new platforms and hundreds of wells, said ANP. Total bonuses were R$21.15 billion.

In March 2018, Round 15 offered 68 blocks and received bids on 47 blocks in seven sedimentary basins. Twenty-two blocks were awarded, with a signature bonus of R$18 billion, marking a new record for concession bidding. Pre-salt production sharing Round 4 in June 2018 awarded three of four blocks–Uirapuru, Dois Irmãos and Três Marias. The 5th Round of pre-salt production sharing bidding, conducted in September 2018, awarded all four offered blocks: Saturno, Titã, Pau-Brasil and Sudoeste de Tartaruga Verde.

Two sharing and concession rounds are in progress. The 6th Round (Fig. 4) planned for this year, is a production sharing round in the Aram, Sagrado do Sul and Brava North areas. Petrobras said it wants to exercise pre-emption rights for Aram, Norte de Brava, and Sudoeste de Sagitario, where it would be the operator. 

Fig. 4. Production sharing Round Six to be held this year includes the Aram, Sagrado do Sul and Brava North pre-salt areas in dark blue. Map: ANP.

Round 16 of concession bids planned for this year offers 42 blocks over almost 30,000 km². The blocks are in the sedimentary basins of Pernambuco-Paraíba, Jacuípe, Camamu-Almada, Campos and Santos. Previous rounds have produced concessions in these areas. 

Planned for 2020 and 2021 are the 7th and 8th pre-salt production sharing rounds. Round 7 in 2020 involves the Esmeralda and Agate areas, in the Santos basin, and Água Marinha, in the Campos basin. 

Round 8 in 2021 is for the Tupinambá, Jade and Ametista areas, in the Santos basin, and Turmalina, in the Campos basin. Round 17 concession bids are planned for 2020, and include blocks in the Pará-Maranhão maritime basins—Pelotas, Potiguar and Santos. Concessions are also planned for Round 18 in 2021, which will offer blocks from the Ceará basin and Pelotas, and ultra-deep waters outside the Espirito Santo basin pre-salt polygon.  

COMPANY HIGHLIGHTS

Petrobras expects to start 19 new production units by 2022, including owned and leased assets in post-salt and pre-salt concessions, production sharing agreements (PSAs), and transfer-of-rights categories. A 2018-to-2022 E&P offshore investment of $60.3 billion will be distributed between production development (77%), infrastructure and R&D (12%), and exploration (11%). Pre-salt activities account for 58% of the investment, with 42% going to post-salt. 

The company’s main project areas include pre-salt concessions Lula Norte and Lula Extremo Sul in the south, and Integrado Parque das Baleias in the north. Post-salt concession projects are Tartaruga Verde e Mestica, Marlim, and Sergipe. Libra is the single production-sharing project, and Buzios, Itapu, Bergiao, Sepia and Atapu are transfer-of-rights projects. 

In a September 2018 presentation, the company said that 93% of 2018 wells had been completed. Production will come with a series of 150,000-bopd capacity startups, including Lula Norte (FPSO P-87), Buzios (FPSO P-75and P-76), and Lula Extremo Sul (FPSO P-69). Additions in 2019 include Engina, with 200,000-bopd capacity (FPSO Engina), and Berbigao with 150,000-bopd capacity (FPSOP-68). 

TheP-76,started in February, is the second of four new facilities planned in Búzios field. Lula field also started production in February, from theP-67 platform. With an estimated 8.3 Bboe recoverable, it is one of the largest ultra-deepwater fields in the world. Lula field is part of the BM-S-11 concession, jointly owned by Petrobras, Shell Brasil Petroleo, and Petrogal Brasil. 

Petrobras underlined its deepwater focus with the November 2018 divestiture of two producing assets. Thirty-four onshore fields in northeastern Brazil were sold to 3R Petroleum for $453 million, and three shallow-water fields off the coast of Rio de Janeiro went to Perenco for $370 million.

The onshore fields have been active for more than 40 years and produce about 6,000 bopd, combined. The offshore fields produce 9,000 bopd from seven platforms and a pipeline to shore. 3R Petroleum is an independent oil company focused on redevelopment of mature fields. Perenco is an independent oil and gas company with operations in onshore and offshore areas in 14 countries. 

Petrobras has assigned Total 35% of its rights and operatorship of Lapa field in Block BM-S-9 in the Santos basin pre-salt. The field was put into production in 2016, using the Cidade de Caraguatatuba FPSO. Petrobras also transferred rights in the Iara area, also in the Santos basin. The agreements are part of a 2016 strategic alliance that includes a focus on deepwater development and other high-potential oil and gas provinces. Technological cooperation agreements have focused, so far, on artificial intelligence techniques to identify geological faults, and processes and tools for low-permeability reservoirs. 

Equinor completed its acquisition of a 25% non-operated interest in Roncador oil field in Brazil’s Campos basin last year. The acquisition is part of Equinor’s strategic partnership with Petrobras to expand technical collaboration. Equinor will attempt to increase Roncador’s recovery factor 5%, to raise total recoverables from 1Bboe to more than 1.5 Bboe.

Equinor is also active as operator in the Campos basin’s Peregrino field, Blocks BM-7 and BM-C-47, where it is a joint owner with Sinochem. The field has production capacity of 100,000 bopd. An ongoing second-phase development (Fig. 5) in BM-C-47 accesses the Peregrino southwest area and involves a third fixed wellhead platform, 15 production wells and six injectors, at a cost of $3.5 billion. Startup is expected by the end of 2020. 

Fig. 5. Equinor’s Phase 2 of the Pergrino field, due to come on line in 2020, includes 15 production wells and six injectors. Image: Equinor; Photographer, Ole Jørgen Bratland©.

ExxonMobil has more than 2.3 million net acres in Brazil, with substantial growth in 2018. The last 24 concessions that ExxonMobil has bought with partners may hold 41 Bbbl of oil, based on preliminary studies by ANP. ExxonMobil said it has interest in 25 blocks in the Campos, Santos, Sergipe-Alagoas, Potiguar and Ceará basins, and its partners include Petrobras, Equinor, Petrogal Brazil, Qatar Petroleum, Queiroz Galvão Exploração e Produção, Murphy and Azibras. The company operates 60% of its acreage position. 

In recent bidding rounds, the company has acquired eight blocks in Round 15, the Uirupuru Block in pre-salt Round 4, and the Titã Block in pre-salt Round 5. Drilling of multiple wells on various blocks is planned for the next couple of years. The company also added to its seismic coverage in 2018 and 2019, including two blocks in the Northern Campos area. 

Winning the Titã exploration block with partner Qatar Petroleum added more than 71,500 acres to ExxonMobil’s portfolio. The company also completed the purchase of half of Equinor’s interest in the BM-S-8 Block that contains part of the pre-salt Carcara oil field. Production from the field, which contains an estimated 2 Bbbl of oil, is expected to start in 2023 or 2024.

Shell is an historic player in Brazil and has been recognized as the leading foreign major in Brazil, with offshore acreage of 2.7 million acres. A pioneer in production-sharing contracts in Brazil, the company, in 2013, entered the Libra consortium, led by Petrobras. It has been active in acquiring pre-salt blocks in recent auctions and in 2017, won three other production-sharing contracts in the Santos basin.

In the June 2018 Round 4 pre-salt auction, Shell expanded its deepwater portfolio. Along with partners Petrobras and Chevron, the company will explore the Três Marias Block, in ​​the Santos basin. In September 2018, Shell and Chevron won the Round 5 pre-salt production-sharing contract for the Saturno Block (Shell 50% operating, Chevron 50%). The company said it plans to drill the Alto de Cabo Frio West and South Gato do Mato pre-salt fields in the Santos basin and is proceeding with seismic studies on two exploration blocks awarded earlier in the year. 

Shell is operator of the Parque das Conchas (BC-10) project in the Campos basin. It is one of the major milestones in the development and commercialization of Brazil’s deepwater oil. The development is the first of its kind, based fully on subsea oil and gas separation and subsea pumping. 

The Parque das Conchas project has three subsea fields connected to the FPSO Espírito Santo,moored in about 1,800 m of water, Fig. 6. Espírito Santo has a processing capacity of 100,000 boed.

Fig. 6. FPSO Espirito Santo produces the three phases of the Parque das Conchas (BC-10) project. Image: Shell.

Phase 3 went onstream in 2016. It is comprised of five producing wells in two Campos basin fields and two water injection wells. The first phase, with nine producing wells and one gas injector well, went onstream in July 2009; Phase 2 tied into Argonauta O-North field during October 2013.  

BW Offshore said that it plans to acquire 70% of Maromba field from Petrobras for $90 million, subject to Brazilian government approval. The Campos basin field, in an approximately 160-m water depth, has estimated recoverable reserves of 100 MMbbl to 150 MMbbl of oil. Eight of nine exploration and appraisal wells drilled to date have found oil in multiple reservoirs. Four of the wells have defined and delineated Maastrichtian sand targets. Maromba is close to Peregrino, Papa Terra, and Polvo oil fields, where BW Offshore has, or has had, operations.  

BW Offshore intends to deploy one of its existing FPSOs to the field as part of a phased development. The company already has two vessels in the region: nearby FPSO Polvo (Fig. 7), and the laid up FPSO Cidade de São Mateus, which recently had its contract with Petrobras renewed. 

Fig. 7. BW Offshore’s FPSO Polvo is stationed near its Maromba acquisition that will also be developed with an FPSO. Image: BW Offshore.

BW Offshore is a leading provider of floating production services to the oil and gas industry, with a global fleet of 15 FPSOs. It also participates in developing proven offshore hydrocarbon reservoirs. WO