The Latin American puzzle

From Brazil pre-salt to Venezuela heavy oil to Argentina shales, diverse region demands industry innovation, flexibility

By Katie Mazerov, contributing editor

The sun is rising on Latin America. With its prolific and varied resources, the region is poised to become a major player on the global hydrocarbon map. While the big story in recent years has been the massive pre-salt discoveries in the deepwater off the coast of Brazil, other countries in the region have emerged into the spotlight as well. From Venezuela’s heavy oil reserves to rich shale deposits in Argentina to the liquids-rich gas fields of Peru to burgeoning unconventional markets in Colombia and Brazil, Latin America holds not just one prize but many.

However, untapping that multifaceted prize is a puzzle, with the wealth of riches tempered by challenges that exist in nearly every market. Regime instability in some countries, nationalized oil companies (NOCs) with varying requirements for private sector participation and lagging infrastructures pose obstacles for development. While small independent operators are sprouting up in many countries, the need for services and expertise often limit private investment to the major international oil companies (IOCs).

“In terms of proven crude oil reserves, Latin America ranks second after the Middle East,” said Adrian Lara, lead analyst for upstream oil and gas for research and consulting firm GlobalData. “Venezuela alone accounts for an estimated 270 billion bbls of heavy crude oil, putting it just behind Saudi Arabia and Canada. But we also have to consider that Venezuela is a country with a lot of economic uncertainty and political instability. Yet even taking Venezuela out of the equation, the region has huge potential,” he continued. “Despite stability issues in most countries, Latin America has a better ranking in terms of country risk when compared with Africa or the former Soviet Union.”

The country with the most near-term potential is still Brazil, home to pre-salt basins that account for the largest oil discoveries globally in recent years. The US Energy Information Agency (EIA) ranks Brazil as the 10th largest energy producer in the world, with 90% of production from deepwater and ultra-deepwater fields in the Campos, Santos and Espirito Santo basins in the country’s southeastern sector. “Campos has been the leading basin for state-owned operator Petrobras since the 1980s and is still the most important offshore basin for Brazil,” Mr Lara said. “Last year, Petrobras scaled back its pre-salt activities to focus on optimizing production in mature fields in the Campos, some of which were showing decline.”

In October, the Brazilian government auctioned off the pre-salt Libra field in the Santos Basin under a new production-sharing contract (PSC) arrangement that lowers the risk for prospective investors but that also will push the government’s share of production higher than under the previous concession contract, Mr Lara said.

“Petrobras and Brazil’s Agency of Petroleum, Natural Gas and Biofuels (ANP) assessed that exploration in the pre-salt regions is not as risky as previously believed and applied this contract structure to the first bidding round for Libra, which is estimated to hold recoverable reserves of eight to 12 billion bbls of oil.”

The new PSC means the state will remain the sole owner of the reserves and production. “After letting the consortium of companies involved in the project recover a percentage of their costs, the state would have a share of 41.65% of this production and will also receive a tax payment based on the share of the investors and royalty payments based on a percentage of gross production,” he explained.

With the government removing all pre-salt areas from subsequent bidding rounds, Mr Lara anticipates it will be at least two years until a second pre-salt round is organized, and in that time the contract terms for the PSC could be altered to attract more investors. Only 11 of the 40 expected companies participated in the recent auction, he noted. The winning consortium also includes Total and Shell at 20% each and China National Offshore Oil Corp (CNOOC) and China National Petroleum Corp (CNPC) at 10% each. “We are expecting further pre-salt licensing to progress at a relatively slow pace, with blocks only being offered once discoveries or prospects have been identified by Petrobras.”

In August 2013, pre-salt production accounted for 15% of Brazil’s total crude oil production. One contributor is the Santos Basin’s Lula field, discovered in 2006 and estimated to hold six to eight billion bbls of oil equivalent (boe), Mr Lara added. Lula is being developed under the previous concession contract, which is considered to be more attractive to outside investment. Petrobras has a 65% controlling interest in Lula, with BG Group holding 25% and Petrogal the remaining 10%.

Mr Lara noted that some uncertainty has followed the October bankruptcy of Brazilian offshore operator OGX, which has been reported as the largest in Latin American history, and that of its sister shipbuilding company OSX in November. OGX began production from its Tubarão Martelo field on 5 December, the company announced. Martelo lies in the BM-C-39 and BM-C-40 blocks and was accessed through the horizontal well TBMT-8H, according to OGX. According to reports, OGX, renamed Óleo e Gás Participações, was at press time near to obtaining new financing to continue operations. However, reported estimates of Martelo’s probable reserves are 87.9 million boe, down from OGX’s initial estimates of 212 million boe.

Petrobras, meanwhile, continues to push the boundaries of deepwater exploration, with a focus on improving production. In the company’s Q3 earnings report released in October, company CEO Maria das Graças Silva Foster reported that reservoirs had been showing higher-than-expected productivity. She also noted that operating efficiency had reached 75% at the Campos Basin Operating Unit and 92% at the Rio Operating Unit, facilitating recovery of 65,000 bbl/day in output for the quarter.

In a 2013-2017 strategic plan presentation to investors in March 2013, the company reported that pre-salt production had reached 300,000 bbl/day, the bulk of the stake belonging to Petrobras. The company projected that its pre-salt production would reach 1 million bbl/day by 2017 and 2.1 million bbl/day by 2020.

“Brazil is not an emerging market. It’s a mature market that is experiencing a rebirth, with a second peak that is going to be enormous,” said Hugh Oliver, rig manager of the floating, drilling, production, storage and offloading (FDPSO) vessel operated by Brazilian private contractor Ventura Petroleo.

“Three years ago, we were alone in the Santos Basin; now there are many new operators, with growth expected to continue for the next 10 to 15 years. The Campos Basin is like a city, with FPSOs littering the horizon,” Mr Oliver said. Brazil is the world’s largest FPSO market. “The pre-salt area alone is enormous – the size of Scotland or bigger. But infrastructure deficiencies, particularly in and around the port city of Macaé, the hub of Brazil’s offshore market, and high import taxes make the market challenging.”

For the pre-salt fields, water depths averaging 2,100 meters (6,900 ft) and the thick layer of salt require heavy-duty drillships. Deepwater contractor Ocean Rig has three DP3 drillships working in Santos Basin’s pre-salt fields in water depths from 2,400 to 2,800 meters (7,900 to 9,100 ft). Two are sixth-generation ships operating for Petrobras, and the third is a seventh-generation unit working for Repsol Sinopec Brasil.

“These ships are among the biggest floating rigs on the market and are what is required to drill in the pre-salt fields, where total well depths can be between 6,000 and 6,500 meters (19,700 to 21,300 ft),” said Christian Girard, vice president and managing director, Brazil, for Ocean Rig. “From the bottom of the sea to the payzone, we have to drill through the salt layer, which is typically 2,000 meters thick and about 1,000 meters of ground. In drilling through the salt layer, it is important to use the correct mud and mud weight to keep the borehole stable.”

The rigs all feature dual derricks allowing dual operations and five mud pumps. The Ocean Rig Corcovado and Ocean Rig Mykonos, working for Petrobras, were built in 2011 and are designed for water depths up to 3,000 meters (10,000 ft). Contracts for both were signed in the low $400,000s, a reflection of Petrobras’ general strategy to seek lower dayrates but award longer-term contracts.

The Ocean Rig Mylos working for Repsol Sinopec Brasil was completed last year for water depths up to 3,650 meters (12,000 ft). Dayrates for the next contract on that rig are expected in the low $600,000s, Mr Girard said.

Ocean Rig has two drillships under construction at the Samsung Heavy Industries shipyard in South Korea: one scheduled for delivery in Q1 2015 and the other for the end of 2015. “Brazil, along with West Africa and Norway, is in our strategic market, and we plan to offer one of the newbuilds for the next call for tender that will be issued in Brazil for the deepwater sector,” Mr Girard added.

Ensco has one drillship, ENSCO DS-4, working for BP in Brazil at dayrates in the mid-$500,000s, and six semisubmersibles working for Petrobras. The dynamically positioned ENSCO DS-4 can drill in water depths up to 10,000 ft, with a maximum drill depth of 40,000 ft. Dayrates for the semis range from the low $320,000s to the mid-$370,000s.

“Regionally we expect Brazil to continue to represent about one-third of floater demand as the development of pre-salt Brazil continues to be a significant growth area,” Kevin Robert, Ensco senior vice president, marketing, reported in the company’s Q3 earnings call on 24 October. By the end of 2013, Petrobras also was expected to conclude the evaluation of bids for workover units needed to help stimulate production for the Campos and Santos basins, he added.

“Petrobras continues its efforts to develop pre-salt as they are working to renew rigs with contracts expiring in 2015 to ensure their resources are efficiently applied toward the high-priority pre-salt developments,” Mr Robert continued. “They entered the market with a formal tender for one or more rigs that we believe is both a market check against the current extension negotiations, as well as recognition that they need more rigs to fill gaps in their forward drilling schedule.”

Two semis, ENSCO 5002 and ENSCO 5004, had been working for OGX but are being mobilized to the Mediterranean.

Sizable reserves also exist outside the pre-salt areas. According to the EIA, Brazil produced 601 billion cu ft (bcf) of dry natural gas in 2012, the majority of which was associated with oil. In May 2013, Brazil auctioned off several blocks to determine whether areas in the northeastern sector of the country share the hydrocarbon potential of areas in West Africa, said José Valera, partner in the Energy Practice Group of Houston law firm Mayer Brown. The firm counsels oil companies on various matters related to the oil and gas industry in Latin America. At the end of 2013, Brazil launched another tender process to determine the potential of the country’s oil and gas shale resources.

A 2013 EIA report estimated that Brazil has 245 trillion cu ft (tcf) of technically recoverable shale gas resources, ranking it 10th globally. Studies by Brazil’s ANP indicate the greatest opportunities for shale gas development are in the Parecis Basin in the Mato Grosso state, the  Parnaíba in the Maranhão and Piauí states, the Recôncavo in Bahia, Paraná in the Paraná  and Mato Grosso do Sul states and the São Francisco Basin in the Minas Gerais and Bahia states.

“In a country as vast as Brazil, it is going to take a long time before we can fully determine the true extent of the potential concerning shale oil and gas,” Mr Valera said. “The good news is that drilling will start in these formations, with the government offering new areas in various bidding rounds.” Whereas Brazil’s pre-salt fields are being developed under PSCs, the rest of the country’s resources remain subject to the original concession contract arrangement under which outside companies are awarded licenses to carry out exploration and production (E&P) of state resources, he noted.

“In the US, companies have developed best practices, both from a technical standpoint and in dealing with regulations, environmental concerns and local communities, so a lot of that knowledge and expertise don’t have to be reinvented in these emerging shale markets in South America,” he continued, noting that opposition is anticipated from landowners and environmental interests in Brazil and throughout South America, where the central government owns oil and gas in place.

However, award criteria often is based on the outside operator’s commitment to incorporating local content, including workers, in operations. “Local content requirements are especially strict in Brazil and have resulted in shortages and increased costs because the country is only now developing the infrastructure to accommodate all the requirements of goods and services by the industry,” Mr Valera said. Lack of infrastructure, especially related to manufacturing and moving equipment in and out, the availability of equipment and technology, as well as water availability, treatment and recycling, all pose challenges throughout the region.

Click here to read about Macaé, Brazil’s offshore oil hub.

In Colombia, the government’s adoption of a legal and contractual framework that encourages E&P investment has, in the past 10 years, more than doubled production of mostly conventional oil and gas, Mr Valera said. “Colombia is a success story, but it could do even better with improvements in security in some of the more remote areas to counter terrorist activity by the Revolutionary Armed Forces of Colombia – People’s Army (FARC).”

Exploration in the country’s offshore oil and onshore unconventional gas basins is under way, following a 2012 bidding round by the Colombian government that offered attractive incentives, GlobalData’s Adrian Lara noted.

Another bright spot is Peru, South America’s only exporter of liquefied natural gas (LNG), where the large liquids-rich Camisea gas field east of the Andes produces more than 100,000 bbl/day of liquids, offsetting declining production of crude oil in recent years, according to an EIA report. The EIA also ranks Peru as having the seventh-largest crude oil reserve in Central and South America, with 579 million bbls of proved reserves, most of them onshore in the Amazon region. In an analysis released in August last year, the EIA put proved natural gas reserves in Peru at 12.7 tcf.

Unlike most countries in the region, Peru’s resources are 100% developed by private-sector companies. “In the early 1990s, Peru privatized all E&P operations and areas held by the state-owned oil company and then instituted a system whereby any private company may apply for production rights in the country,” Mr Valera explained.

Argentina ranks third globally in technically recoverable shale gas reserves, with an estimated 802 tcf, according to a 2013 report released by the EIA and Advanced Resources International, an energy consulting firm. “Actual results from drilling in the Neuquén Basin are confirming that, from a geological standpoint, Argentina has probably the best-quality shale rock in South America for production purposes,” Mr Valera said. “The paradox is that, while Argentina has one of the world’s best shale reserves, government regulations that put severe controls on price, imports/exports, foreign currency exchange rates and labor have made it a financially risky place for outside investment,” he noted. “Argentina is going to remain a natural gas importer for the foreseeable future.”

In July, Argentina began offering incentives for $1 billion, five-year investment plans, which include exemption from oil and gas export duty for up to 20% of production after five years from the project start, and the right to retain all foreign currency received from the sale of this 20% production share, Mr Lara noted. The program was introduced at the same time as the announcement of an investment deal between state-owned Yacimientos Petrolíferos Fiscales (YPF) and Chevron to develop the Neuquén Basin’s prolific Vaca Muerta shale.

“Given the timing and the fact that the Chevron-YPF deal fulfills the requirements to benefit from the new scheme almost to the letter, it is clear that the law was prepared in tandem with the Chevron negotiations and that a primary purpose of the incentive is therefore to promote the development of the Vaca Muerta,” he said. “As this amendment is so recent, we are not expecting any further incentive programs to be added in the short term. However, this Chevron deal suggests that other investors may be able to negotiate individual benefits in contracts with YPF.”

Despite the recent changes to Argentina’s fiscal terms, other investment barriers, including economy-wide restrictions on the repatriation of profits and domestic price controls and inflation, will prevent a more positive outlook for the country’s oil and gas industry over the coming years, Mr Lara suggested. “These factors will limit the effect of new incentives, at least until the upcoming election in 2015, with little indication that the situation may change prior to this.”

Nabors has 22 rigs drilling in both conventional and unconventional reservoirs in Argentina and is delivering four additional rigs for the shale oil and gas factory drilling program that YPF is expected to launch this quarter in the Vaca Muerta, estimated to hold 660 billion bbls of oil in place and 1,181 tcf of oil-gas in place, according to Victor Villegas, vice president of Latin American operations for Nabors.

Two rigs were delivered in January, with others scheduled for February. All four are AC rigs with skidding systems. The factory drilling pilot program includes 48 horizontal wells and 84 vertical wells. In addition to drilling with YPF in the Argentinian shale play, Nabors has drilled for Chevron and was recently awarded new-technology drilling rig contracts for Shell and Total in the Neuquén operating area.

YPF, which has formed joint ventures with major IOCs Chevron, Statoil and Shell and with smaller Argentine E&P companies, such as Medanito and Pan American Energy, to develop unconventional resources, is aggressively contracting specific rigs and services for the factory drilling program.

“YPF tendered for 30 rigs in 2012 and is tendering for 20 additional rigs, all focused on the shale play in and around the Neuquén Province,” Mr Villegas said. “While YPF awaits new-generation rigs with skidding systems to arrive in country, it has been laying the groundwork with equipment that is available, building pads of two rows of four wells each and concurrently drilling a well on one row and fracturing a well on the other row.”

The arrival of the latest-technology rigs is expected to improve market dayrates, which historically have been low because of the significant oversupply of older-generation rigs in the country, he added. “We will continue to upgrade some of our older-generation drilling rigs in Argentina as YPF’s long-term plan through 2020 calls for the phasing out of the older-generation drilling rigs in the interest of safety and drilling efficiency,” he noted.

Including Mexico, Nabors has 58 drilling and workover rigs working throughout Latin America, with a 93% utilization rate, Mr Villegas said. Pending various tenders, an additional seven rigs may be added in 2014. The Nabors fleet in Latin America includes 14 rigs in Mexico, 13 rigs in Colombia, five AC rigs with skidding systems in Venezuela and six rigs in Ecuador, along with four workover rigs and two 2,000-hp rigs drilling for conventional gas and oil. Two of the AC rigs in Colombia are being moved to Argentina.

In Venezuela’s heavy oil-rich Orinoco oil belt, Nabors’ work is with joint ventures, where IOCs partner with state-owned Petróleos de Venezuela (PDVSA), with PDVSA holding the controlling interest. Nabors, which has operated in Venezuela for more than 50 years, has three rigs working in the East, including two for Petrocedeño, a JV with PDVSA and Statoil, and one for Petropiar, PDVSA’s JV with Chevron. Two programmable A/C electric, or PACE, rigs are working for the Petroboscan heavy oil JV with PDVSA and Chevron in western Venezuela, according to Mr Villegas.

“Venezuela has an ambitious plan to purchase more than 100 rigs from China, and while PDVSA Services, the in-house drilling contractor, has displaced many international drilling contractors, our performance and reliability have been key differentiators for PDVSA to extend our drilling rig contracts,” he said. Colombia has seen a decrease in security issues, making most operating areas safe, Mr Villegas continued.

While the country has some shale gas potential, current production is conventional oil and gas, primarily in the Llanos Basin where state-owned Ecopetrol has more than 30 rigs working. Nabors has six rigs in the Llanos Basin and seven spread out in different operating areas.

“Three years ago, Ecopetrol awarded contracts for eight tenders for modern rigs to Nabors, four of them brand-new, four refurbished,” Mr Villegas said. “With a reduction in use of older-generation rigs and the push for an increased number of newer-generation AC rigs operating in the country, we expect  there is pressure to raise dayrates, which have been soft in recent years.”