Considering Brazil’s state-owned Petrobras has more than 900 projects planned as part of an approximately US $237 billion five-year investment plan, few if any can argue that the company does not have its plate full.

But the deepwater powerhouse is confident in its ability to get the job done despite concerns raised about whether or not it can handle the hefty workload and serve as operator for presalt developments. When asked to address such concerns, Petrobras pointed to its experience.

“The large amount of technology developed by Petrobras in oil [E&P] in deep and ultra-deep waters throughout its history, mainly in the Campos basin, has turned Petrobras into a company that is internationally recognized for its excellence in this area,” the Petrobras Press Office said in an emailed statement to E&P. “This expertise makes us feel comfortable, ensuring that we do not have barriers to develop presalt production.”

Evidence of Petrobras’ past successes followed: 63% of the world’s deepwater oil discoveries are in Brazil, Petrobras has more deepwater production systems than any other company operating in such conditions, high-resolution seismic has resulted in higher exploratory success, selection of new materials has lowered costs, geological and numerical modeling has led to better forecast of production behavior, and separation of CO2 from natural gas in deepwater and reinjection has reduced emissions and increased the recovery factor.

“Various advances have been made in recent years that not only allow drilling to be stable in the salt layer but that also reduce time and investment to drill the well,” the Petrobras Press Office said. “The first well drilled by Petrobras in the pre-salt, between 2005 and 2006, took about 15 months and cost $240 million. Currently, with the incorporation of various improvements in materials and operating procedures, the same operation lasts around 70 days, with a cost of $70 million.”

But reality hasn’t escaped Petrobras. “Given the huge scale of the presalt discoveries and operations, the benefits of continuous innovation will be even more significant if you compare [the presalt] to any deepwater field in Brazil, the Gulf of Mexico [GoM], or the North Sea,” Petrobras said. “Obviously, we are continuing to work to reduce costs and increase productivity.”

Reality hits home

Petrobras already has been reducing its commitments abroad in some areas, a move that could allow the company to concentrate more on domestic projects. In August Petrobras announced the sale of its 35% stake in Block BC-10, known as Parque das Conchas, to Sinochem Group for $1.54 billion and the signing of $185 million in farm-out contracts related to 100% of Petrobras’ stake in blocks MC 613 (Coulomb), GB 244 (Cottonwood), and EW 910, all in production in the US GoM. The company plans to put up for sale $9.9 billion of assets, mostly before year-end, as it works to increase production from the current 2 MMb/d to 4.2 MMb/d by 2020.

“To reach this oil output and meet the local content levels, we [revived] the offshore industry in Brazil,” Petrobras CEO Maria das Graças Silva Foster said in a news release. “We now have a number of shipyards that have returned to business after being idle for years and years, and we had to work hard for that to happen.”

Increasing production also mandates more investment in logistics infrastructure, which led Petrobras to create the Logistics Infrastructure Optimization Program (Infralog). “By 2020, $6 billion will be invested in expanding port, airport, and oil terminal capacity,” Silva Foster said. But growing pains are evident as delivery delays impact operations.

Subsea 7, which landed a $1 billion engineering, procurement, installation, and commissioning contract for Petrobras’ Guara and Lula presalt discoveries in the Santos basin, has taken a financial hit on the project. During a conference call Aug. 14, Subsea 7 CEO Jean Cahuzac said the company suffered a net loss of $13 million in 2Q 2013 due partly to a $300 million loss on the Guara Lula project, which has faced delays in equipment delivery abroad. Weather conditions also have impacted installation operations for the project, which now has moved into the main offshore phase with the Seven Polaris and the Seven Oceans on location. “Overall, the project remains challenging,” Cahuzac said during the call.

Conditions appear to have improved somewhat, although the circumstances have given Subsea 7 reason to concentrate on contracts with lower risks.

“We have made good progress with procurement and importation of equipment. The key components of the buoy systems are now either in Brazil or will arrive in Brazil in the coming weeks. The supply chain is not presently on the project-critical path, although we are still experiencing some challenges with one of our subsea equipment suppliers in Norway,” Cahuzac said. “We are working jointly with Petrobras to overcome this specific issue in a timely manner.”

Pondering change

Overseeing billions of dollars’ worth of projects in the coming years will be a challenging job for Petrobras, said Manouchehr Takin, senior petroleum upstream analyst for the Center for Global Energy Studies.

“Imagine any engineering project,” said Takin, author of the recently published report, “Brazil reopened: Do we expect too much oil too soon?” “You have to evaluate what you need to target; do detailed engineering; develop plans that require so many disciplines working together in different stages; and try to find equipment, get some buyers, and order it. It is a major operation to supervise and lead these activities.… People are saying maybe Petrobras is overextending itself.”

Brazil’s first presalt round – set for Oct. 21 – will mark the country’s first use of the production-sharing model. The winner will be the company that brings the best offer. Petrobras will serve as operator with at least 30% participation. The government’s take will be the sum of the signature bonus, income tax, and a percentage of profit oil, coming to 75%.

Terms of the production-sharing contract have generated concern, including supply chain problems, infrastructure woes, and other delays caused by customs clearance issues as well as concerns about taxes and environmental issues.

One person who attended an Aug. 8 event in Houston, where Brazilian National Agency of Petroleum and Biofuels (ANP) Director-General Magda Chambriard spoke about upcoming 2013 bidding rounds, questioned whether the 30% participation and operating requirements for Petrobras could be flexible. “There is the question of whether Petrobras can actually handle everything that it is going to be required to do the way you designed the regime,” the questioner commented.

In response, Chambriard said it is the law. “Law is something that is very well-defined. We’ve spent some years discussing this with the Brazilian society, including Petrobras.”

However, Takin pointed out that while Brazil is open to foreign investors, international companies like to be more hands-on. “[Petrobras and Brazil] have this background because they didn’t know these easy targets would be discovered. For Brazil’s own good, it’s better to reduce this monopoly of operation to avoid bottlenecks and delays that inevitably will occur.”

A bill presented by Brazil Congressman Raul Henry would reverse the 2010 law that mandated Petrobras operate and hold a 30% stake in presalt areas under the production-sharing regime. If approved, the change could not only lessen the burden placed on Petrobras but also open the area to more private-sector investment, potentially reducing development delays.

Serving as operator does have benefits, which according to the Petrobras Press Office include the ability to increase technological resources and integrate resources such as logistics, rigs, and support vessels to develop production.

Another perspective

Meanwhile, problems are mounting for cash-strapped OGX, which has missed production targets. After analyzing its three production wells in the Tubarao Azul fields, OGX announced in July that “there is no technology currently available that would economically allow the development of the Tubarao Tigre, Tubarao Gato, and Tubarao Areia fields.” OGX said the wells – which are not in the presalt region – could cease to produce in 2014, prompting the company to submit revised field development plans to the ANP.

But the Tubarao Martelo field will continue to be developed as planned, OGX said in a news release.

The woes being experienced by some, however, are not expected to deter others, considering the opportunities that Brazil holds in not only the presalt region but also shale gas onshore and in the Equatorial Margin.

In fact, Shell CEO Peter Voser has confirmed that the company is interested in participating in upcoming licensing rounds this year. Shell also has plans to boost production offshore Brazil with two new deepwater projects at BC-10 and the Bijupira/Salema fields.

Phase 3 of BC-10 will include the installation of subsea infrastructure at the Massa and Argonauta O-South fields, which Shell said will be tied back to the FPSO vessel Esp?rito Santo. Peak production could reach 28,000 b/d. Plans for the Bijupir?/Salema fields include four new production wells, which are expected to increase production to 35,000 boe/d in 2014.

Great potential

Brazil had proven reserves of about 15.3 Bbbl of oil and 459 Bcm (16.2 Tcf) of natural gas in 2012. The country produced about 2.2 MMb/d of oil and NGL and about 71 MMcm/d (2.5 Bcf/d) of gas. Hopes are to double each of these figures in the near future, according to the ANP.

Grabbing most of the attention nowadays is the country’s presalt development. Currently, 17 presalt wells are producing 320,000 b/d of oil. Possibly holding between 8 Bbbl and 12 Bbbl of recoverable oil, the presalt Libra prospect is much bigger than the ANP first thought. The new estimate, up from 5 Bbbl, is based on new 3-D seismic data and is sure to attract more interest in the highly anticipated presalt bidding round.

“We don’t have any notes about any other country offering such an opportunity [that is] already drilled, already discovered, already tested,” Chambriard said. “We tested the well that discovered the Libra area.… From this well, we got a net pay of 326 m (1,070 ft).”

Producing 27°API oil, the well flowed at 3,667 b/d during a first test and 1,057 b/d in a second test, Chambriard said, later adding that the well could be a good producer, yielding 25,000 b/d to 30,000 b/d easily. As of April 2013 there were 295 MMb/d of oil and 9.9 MMcm/d (350 MMcf/d) of gas of presalt production, with the highest amount coming from four wells in the Lula field.

The Brazilian government also has approved its 12th bidding round, making available more than 163,000 sq km (62,935 sq miles) spanning seven onshore basins believed to hold natural gas and shale potential. During the Houston event, Chambriard glorified the region’s prospects and pointed to a photo of a large flame in the Paran? basin’s Barra Bonita field as evidence.

“Gas for sure is there. The field is a small field, but I can assure you that from my years in the petroleum sector I’ve never seen a basin so big with only one discovery,” Chambriard said. “For sure we have much more.”

She then turned attention to a photo of the Teles Pires River in the Parecis basin. “In this river, we have 800 m [2,625 ft] of bubbling gas,” Chambriard said. “The gas is bubbling so strongly that we can even record the sound.”

The bid round – which will offer in November 2013 acreage in the Acre, Parecis, Parana, Parnaiba, Bacia de Sergipe-Alagoas, Reconcavo, and Sao Francisco basins – includes unconventional opportunities, Chambriard said. Using the Barnett shale with reserves of 850 Bcm (30 Tcf) as its analogue, forecasted in situ volumes are 1.8 Tcm (64 Tcf) for Parnaiba, 3.5 Tcm (124 Tcf) for Parecis, 566 Bcm (20 Tcf) for Reconcavo, and 2 Tcm (80 Tcf) for Sao Francisco. Based on data from the US Energy Information Administration, the forecasted volume was 6.4 Tcm (226 Tcf) for Paran?. “No one else can doubt Brazil has great opportunities in great areas,” Chambriard said.

More, more, more

The year 2013 has brought news of three bid rounds offering concession and production-sharing contracts, including the first for the presalt region. Alex Vartan, vice president of South America MultiClient for Petroleum Geo-Services (PGS), said the industry needs to have consistent licensing rounds and that those rounds should include the presalt areas.

“A number of seismic companies have made significant investments in acquiring data in the presalt area [specifically the Santos and Campos basins],” Vartan said. “Where we’ve acquired most of our data as an industry is yet to come back into those licensing rounds. Politically speaking, our belief is that it can only be a good thing for industry once the presalt rounds start.”

Bid rounds resumed this year following a hiatus that started in 2009 as the government formed policies and established the presalt regulatory framework.

In the last few years PGS has acquired two sizable datasets, including 2,300 sq km (888 sq miles) of data in central Santos, Vartan said, later adding he foresees more wide-azimuth or multi-azimuth surveys being shot over the region’s presalt acreage. “We’re now looking to move toward a higher imaging solution.”

The other dataset covers blocks that were awarded to Eni, Petrobras, and Repsol in licensing round 8 but never finalized. The blocks were eventually recovered by the government once the round was suspended, Vartan said.

“At the time, the blocks that Eni bid on were the highest signature bonuses in Brazilian history. It signals a very prospective area in the presalt that we’ve acquired data over, but we now have little opportunity to actually license those data until the blocks become available in a round again,” Vartan said. It is unknown when that could happen.

“It’s becoming a more political discussion now that Petrobras is struggling with the potential investments that it is exposed to in the presalt areas. What we may see is that those bid rounds are significantly delayed until such point that Petrobras is stronger financially to take care of that commitment,” Vartan said. “The legislation as it is written has placed an enormous onus on Petrobras in relation to the presalt areas. Also, that onus and potential delay have created significant problems and delayed revenues for the seismic companies that also have invested in those presalt areas.”

Regardless of whether legislators enact change, companies are expected to continue flocking to Brazil, considering the amount of recoverable oil, recent discoveries, and future potential. “The prize is too good to miss,” Takin said.

R&D plays major role in Brazil’s energy industry

A study by OTM Consulting delves into how to maximize the value of billions of dollars for R&D projects.

By Velda Addison, Associate Online Editor

Oil and gas companies are expected to shell out nearly US $1.2 billion annually by 2014 for R&D projects, at least 50% of which will be spent at Brazilian universities, due to a levy imposed by the country’s government, according to OTM Consulting. The other 50% will be spent on in-house R&D and R&D service companies.

And that amount could grow to around $10 billion cumulatively by 2022, according to Shahnawaz Vahora, a senior consultant with the firm. Considering the substantial amount of money, OTM conducted a study with a goal of determining how to maximize the investment for the benefit of E&P companies, universities and research groups, the government, and the Brazilian people.

The study, titled “Understanding the full extent of R&D capability within Brazilian universities,” and its findings are set to be unveiled during OTC Brasil in October.

“The biggest challenge Brazil has is in successfully exploring the presalt resources,” Vahora said, noting that the layer of salt above the oil-bearing zone can be between 2,000 m and 3,000 m (6,562 ft and 9,843 ft) thick. “If you look at it from the molecule perspective, there are challenges to be overcome all the way from the reservoir to the production tubing to floating production units to onshore pipelines.”

There is difficulty in looking beneath the salt to determine how much oil is in place. Drilling through the thick salt layer with the currently available drillbits can be challenging, and ensuring well integrity – considering salt tends to move over time – presents another obstacle, Vahora added. Other necessities include having riser systems capable of handling HP/HT conditions and quality flow assurance so that oil flow to the production unit is seamless.

“The majority of R&D coming on will be looking to solve some of these issues,” Vahora said. “The great thing about these R&D topics is that they are analogous to the whole of the deepwater ‘Golden Triangle’ [the Gulf of Mexico, offshore West Africa, and offshore Brazil], and all of them will benefit from the outputs from this research.”

State-owned Petrobras also is looking to create several centers of excellence surrounding universities to conduct R&D projects, Vahora said. Notable among them are the Numerical Offshore tank at the University of S?o Paulo, looking at wave interaction with floating hosts; InPetro at Federal University of Santa Catarina, focused on the digital oil field, flow assurance, and condition monitoring; and LabRiser at the University of Campinas, focused on delivering world-class research on deepwater risers.

As part of its study, OTM visited universities known for specializing in E&P R&D and spoke to professors to learn about their technical abilities and offerings as well as to identify gaps to determine what is needed in Brazil. Visits were made to six world-class E&P research universities in Europe and the US – the University of Oklahoma, Rice University, Texas A&M University, and Imperial College among them.

The assessment included face-to-face visits, questionnaires, and intensive desktop research to establish a benchmark as well as a comparison of how Brazilian research groups compare to their counterparts abroad.

“Brazil really struggles in terms of finding personnel and recruiting new Ph.D. students and researchers,” Vahora said. “The biggest challenge is how to get people for upcoming projects and developing a support structure. A number of these Brazilian universities are in their infancy stage if you compare them to world-class universities that have a track record.”

OTM also found that some universities initially get large amounts of money from sponsors for research, but the money runs out. The legal obligation for companies to invest in R&D in Brazil is a positive for the country.

However, researchers’ struggles in Brazil often include a lot of bureaucracy and too much time spent on mundane project management instead of conducting research, Vahora said. OTM also noted that research centers in Brazil are clustered around the Santos and Campos basins in Rio de Janiero and Sao Paulo.

“The current perception is that the north is underdeveloped compared to the south, and a lot of money is being focused on the south of Brazil,” Vahora said. “These research centers need to be spread across Brazil.” The money needs to go to the north as well as the south to develop local supply chains and access local talent.

OTM recommended developing› a larger resource pool by recruiting and retaining research professionals, maintaining competitiveness among research groups, and fostering collaboration instead of competition among oil companies.

“Research groups also can learn from these new guys that are coming to Brazil,” he said, pointing out the technology and R&D legacies of companies like Statoil and Chevron. “This helps make the universities become even more world-class.”