May 2017

Regional Report: Latin America

Latin America schleps forward on its quest for recovery
Emily Querubin / World Oil

With crude prices hovering around $50/bbl, nations in Latin America are finding it difficult to boost their steadily declining production rates. Proposed border taxes, land auctions, and a changing landscape in global trade, have ignited civil unrest throughout the region, making a comeback in E&P activity more unlikely. However, several recent discoveries, and an influx of foreign energy companies, may be Latin America’s ticket to recovery.


With South America’s second-largest economy, Argentina holds plentiful shale reserves. However, high inflation rates and significant debt, along with the oil and gas industry’s recent downturn, have deteriorated the country’s ability to capitalize on its resources. Despite reports that the government may eliminate production subsidies by the end of 2017, which will likely aid in attracting investors, the country’s energy sector continues to struggle financially.

Petrobras, Brazil’s state-owned oil producer, has felt the effects of the industry slump and, in May 2016, announced the imminent sale of assets in Argentina and Chile. The company agreed to sell its 67.2% stake in Petrobras Argentina SA to Pampa Energia SA for $892 million. However, Petrobras reportedly retained its 34% stake in Argentina’s Rio Neuquén natural gas concession. Following the acquisition, Pampa Energia SA reportedly switched its focus to the production of tight gas, claiming that the prospects appeared to be more profitable than shale gas.

According to Wood Mackenzie, many operators in Argentina are focusing on reversing the Neuquén basin’s gas production decline by targeting low-permeability, tight gas reservoirs. The switch is reportedly motivated by pricing incentives and lower costs. Wood Mac reported that tight gas production in the basin has tripled in the last few years, reaching 565 MMcfgd in first-quarter 2016.

YPF SA, Argentina’s largest oil company and indigenous producer, also announced plans to divest non-core assets in August 2016. Announcement of the divestiture followed a significant second-quarter loss of $50.7 million.

In February 2017, however, YPF agreed to a partnership with Shell to develop a shale gas pilot project in Vaca Muerta. Under terms of the agreement, each company will hold a 50% working interest in Bajada de Añelo—a 55,000-acre area situated northeast of Loma Campana. The region is said to hold both shale oil and shale gas resources. According to Shell, an estimated $300 million will be invested in the project.

Exxon Mobil has increased its investment in Argentina’s Vaca Muerta shale formation, as well. The oil giant already has invested about $200 million in the shale gas deposit, which is believed to be the second-largest in the world. In June 2016, it was announced that an additional $10 billion would be spent in the next several decades, $250 million of which had been earmarked for an upcoming pilot project. It was reported that the pilot project would determine whether or not to move forward with a 20-to-30-year full development period.

The Vaca Muerta formation, in Argentina’s Neuquén basin, has been the country’s primary focus for resource development of late. According to IHS Markit, the unconventional energy play—which covers an area the size of Belgium—could potentially produce 2.8 Bbbl of oil and 33 Tcf of gas by 2040. “The Vaca Muerta has the potential, not only to reverse Argentina’s conventional production declines and satisfy its growing domestic energy demand, but also to enable Argentina to regain its position as an oil and gas exporter,” said Ricardo Bedregal, director for upstream research and consulting at IHS. “However, for the required investment to materialize, the government must continue to provide both assurance and a regulatory environment that gives long-term stability to investors.”

In March, Madalena Energy began its $9.8-million multi-frac re-entry in the Vaca Muerta, at Coiron Amargo Sur Este (CASE). The drilling program is comprised of two well re-entries. Madalena’s partners in the CASE project include Pan American Energy (55%) and Gas y Petroleo del Neuquén (10%).

At the Puesto Guardian concession, in Argentina’s Salta Province, President Energy announced that it had begun its workover rig program in February. The company’s plans reportedly include a multi-well frac program in three consignments. It maintains a production target of 1,200 bopd by the end of the summer. The first successful workover was completed in March. The previously producing well—DP12, at Dos Puntitas field—achieved an initial production rate of more than 120 bopd. The second workover, DP1001, was also complete by the end of the month, bringing the Puesto Guardian concession’s initial flush production to approximately 750 bopd.

Wintershall is another active company in the southern Argentinean province of Tierra del Fuego. According to the company, approximately 19 MMcfgd had been produced during 2016 from the CMA-1 area, which includes Carina and Aries fields.

With its partners—Total (operator) and Pan American Sur—Wintershall put Vega Pléyade gas field into production in February 2016. The field, which holds reserves of about 25 Bcm—lies in the Argentine Sea and is producing up to 8.5 MMcmgd.


As the largest country in South America, Brazil produces significant amounts of oil from its pre-salt layer, which accounts for 40% of Petrobras’ Brazilian output. The country recently has been referred to as the fastest-growing oil producer outside of OPEC. Its pre-salt region, alone, produces about 1.3 MMbopd, and is expected to exceed 2 MMbopd by 2023. This would surpass the production rate of Norway, as well as a number of OPEC producers.

With partners Statoil (35%) and Petrobras (30%), Repsol Sinopec Brasil (35%) announced completion of the Gavea A1 well in April. The well—which can be found in the ultra-deep, pre-salt Block BM-C-33 in the Campos basin—encountered a hydrocarbon column of about 574 ft. The column was reportedly in a good-quality reservoir in the Macabu formation. After reaching a TD of nearly 20,440 ft, the well started producing approximately 16 MMscfg and 4,000 bopd. With four completed appraisal wells in the license, the consortium reportedly plans to evaluate the sub-surface data to devise a cost-effective development model.

Petrobras persevered last year, as it juggled the political instability surrounding President Dilma Rousseff’s impeachment, as well as its $15.1-billion divestment plan. In June 2016, the company reported that pre-salt production had surpassed 1.0 MMbopd, less than 10 years after the deposits were discovered. Petrobras E&P director Solange Guedes said, “Pre-salt production projects are now Petrobras’ main focus of investment, due to their strategic importance and high profitability. Together, with other projects in our portfolio, they guarantee greater predictability for our production targets and curve.”

In July 2016, Petrobras announced the start-up of the Lula Central production system at Lula field, in Brazil’s Santos basin. With the interconnection of the first production well (8-LL-81D-RJS) to FPSO Cidade de Saquarema, output reportedly stabilized at about 30,000 bopd. The Lula Central project, situated more than 186 mi off the coast of Rio de Janeiro, is made up of nine production wells and nine injectors. According to the company, it is the tenth-largest production system operating in the pre-salt layer. The project is part of Petrobras’ annual production target of 2.145 MMbopd in Brazil.

In October, a shift in Brazilian policy drew the attention of numerous oil majors. Congress removed a regulation requiring that all new operations in the pre-salt layer be controlled by state-owned Petrobras. The country is expected to auction off four more blocks in the prolific pre-salt region later this year. Eliminating the rule has opened the door to investment opportunities and increased competition, and oil majors are said to be lining up to cash in on the region’s resources. Petrobras CEO Pedro Parente told Bloomberg, “Our foreign ministry representation unit in Houston, the very following day, received seven manifestations of interest of big companies.”

For a total consideration of $2.5 billion, Statoil acquired Petrobras’ 66% operated interest in the BM-S-8 offshore license in November 2016. The license, which is found in the Santos basin, contains a significant portion of the Carcará pre-salt discovery—one of the largest in the world, with estimated recoverable reserves between 700 MMboe and 1.3 Bboe.

In Brazil’s Solimoes basin, Rosneft began drilling its first exploration well in February. The company reportedly has plans to drill at least four wells, in an effort to obtain critical data that will help determine the basin’s hydrocarbon potential.


Despite having what it says are the world’s biggest oil reserves, Venezuela’s energy sector was ravaged by the recent industry downturn. Its oil industry has been besieged by one of its worst financial crises in history. Economically, Venezuela has fallen into a depression. Shortages of food and basic goods have been reported, resulting in public outcries of dissatisfaction with President Nicolas Maduro.

In April 2016, Schlumberger announced that it would make significant cutbacks in Venezuela, due to the national oil company’s inability to make payments. As overdue payments continued to mount, Halliburton made a similar announcement the following month. “We have experienced delays in collecting payment on our receivables from our primary customer in Venezuela. These receivables are not disputed, and we have not historically had material write-offs relating to this customer,” the company reportedly said in a filing with the U.S. Securities and Exchange Commission.

Petroleos de Venezuela SA (PDVSA), the state-owned producer, reported in June 2016 that it was confident that it could avoid default on its multi-billion-dollar debt, if crude prices regulated around $50/bbl. Meanwhile, the country’s production—which represents approximately 95% of its foreign currency revenue—declined to a 13-year low, to 2.15 MMbopd. The biggest production losses were reportedly confined to the mature fields of eastern Venezuela. According to Baker Hughes, the rig count fell by 10 in May 2016, to 59 rigs—the lowest level in over a year.

As the country’s economic woes continued to worsen, with exports falling more than 300,000 bopd, President Maduro reportedly reached out to other producers, including Russia, Iran, Saudi Arabia and Qatar, in August. “The price of oil, for necessity, can and needs to rise to $70/bbl,” Maduro said. “It’s easy. The economy would assimilate that price perfectly, and it would be a motor for economic growth worldwide. We have a plan that’s been assumed and approved by OPEC and non-OPEC producers, and we’re going to keep building consensus about the plan.”

Bloomberg reported in April that, even under the best of circumstances, a turnaround for Venezuela’s energy industry could take at least two years.


Fig. 1. In June 2016, Exxon Mobil and its partners announced results of the Liza-2 well, the second exploration well in the 6.6-million-acre Stabroek Block. Recoverable resources were confirmed between 800 MMboe and 1.4 Bboe. Source: Exxon Mobil.
Fig. 1. In June 2016, Exxon Mobil and its partners announced results of the Liza-2 well, the second exploration well in the 6.6-million-acre Stabroek Block. Recoverable resources were confirmed between 800 MMboe and 1.4 Bboe. Source: Exxon Mobil.

Historically, Guyana has not been considered a potential energy producer of great consequence. However, recent discoveries by Exxon Mobil have put the country on the oil market map. In June 2016, the oil giant announced results of its Liza-2 well, the second exploration well in the 6.6-million-acre Stabroek Block, Fig. 1. Recoverable resources were confirmed between 800 MMboe and 1.4 Bboe.

Liza-2 was drilled approximately 2 mi from Liza-1, which was completed in 2015. The wells are situated about 120 mi offshore. Steve Greenlee, president of Exxon Mobil’s exploration company, said, “We are excited by the results of the production test of the Liza-2 well, which confirms the presence of high-quality oil from the same high-porosity sandstone reservoirs that we saw in the Liza-1 well.”

Exxon, which owns a 45% stake in Liza field, plans to formally invest in the oil discovery by the end of this year. The company’s partners include Hess Corp. (30%) and CNOOC Ltd. (25%). Using Stena AB’s Stena Carron drillship (Fig. 2), Exxon has disclosed plans to drill additional wells near the discovery.

Fig. 2. Using Stena AB’s Stena Carron drillship, Exxon has disclosed plans to drill additional wells near the Liza discovery in Guyana. Photo: Hess Corp.
Fig. 2. Using Stena AB’s Stena Carron drillship, Exxon has disclosed plans to drill additional wells near the Liza discovery in Guyana. Photo: Hess Corp.

In January 2017, Exxon Mobil also announced positive results from its Payara-1 well—found approximately 10 mi northwest of Liza. Also in the Stabroek Block, the well was drilled in a separate, but similarly aged reservoir. The well encountered more than 95 ft of high-quality, oil-bearing sandstone. It was drilled to a depth of 18,080 ft, in 6,660 ft of water. It was reported that the additional resource would be evaluated subsequently for development, in conjunction with the Liza discovery. Startup is expected by 2020.

In March, Exxon reported more positive results offshore Guyana. The Snoek well—also in the Stabroek Block, about 5 mi southeast of Liza—encountered 82 ft of high-quality, oil-bearing sandstone. It was drilled to a depth of 16,978 ft, in 5,128 ft of water. Following completion of the well, the Stena Carron drillship was reportedly being moved back to Liza field, where it would begin drilling the Liza-4 well.


Although it is rich in natural resources, Colombia has found it increasingly difficult to develop them for various reasons, including rebel attacks and permit delays.

Fig. 3. After increasing its 2016 capital plan by $34 million, Canacol Energy announced in September that it would double drilling activity in Colombia. Photo: Canacol Energy.
Fig. 3. After increasing its 2016 capital plan by $34 million, Canacol Energy announced in September that it would double drilling activity in Colombia. Photo: Canacol Energy.

Canacol Energy, however, has been successful in Colombia, despite the industry slump. It has reported four new gas discoveries in Colombia over the past three years, increasing its 2P reserves in the Esperanza and VIM 5 Blocks by 302 Bcf. After increasing its 2016 capital plan by $34 million, the company announced in September that it would double drilling activity in Colombia, Fig. 3. The company reported three new gas wells in the Lower Magdalena basin—the Trombon-1 exploration well, the Nelson-6 exploration well, and the Nelson-8 development well. According to Canacol, the extended drilling program was meant to target an estimate of more than 100 Bcf of new potential recoverable resources during 2016, and to increase the productive capacity of the company’s gas assets to more than 190 MMcfgd.

GeoPark Limited, too, has had significant success in Colombia, of late. In October, the company announced that it had completed drilling of its Tigana-4 development well in the Llanos 34 Block. The well, which was drilled to a TD of 11,150 ft, was reportedly producing at a rate of over 3,200 bopd. According to GeoPark, Tigana field produces approximately 15,000 bopd, gross, from eight wells. It is situated along the same trend and fault line as Jacana field, where GeoPark is now drilling the Jacana-6 appraisal well.

In February, GeoPark reported further exploration success in Colombia’s Llanos 34 Block, following the discovery of Chiricoca field. The company drilled and completed the Chiricoca-1 exploration well to a TD of 11,966 ft. Production tests showed a flowrate of approximately 1,000 bopd. Concurrently, GeoPark announced the completion of the Tigana Sur 6 development well, which sustained a production rate of about 1,600 bopd. It had been drilled to a TD of 11,645 ft, encountering good-quality reservoir in the lower Gaudalupe formation.

South of Colombia, in Peru, GeoPark announced that it had obtained final regulatory approval to acquire the Morona Block in December. State-owned Petrόleos del Perú SA awarded a 75% working interest in the block, as well as operatorship, to GeoPark. The Morona Block covers an area of 1.9 million acres in the Marañόn basin. The basin is considered one of the most prolific in Latin America, with more than 1 Bbbl of oil produced. The block reportedly contains great exploration potential, which includes gross unrisked exploration resources between 300 MMbbl to 500 MMbbl.

Fig. 4. Incahuasi gas and condensate field, Total’s first operated development in Bolivia, was brought onstream in early August. The field, which has estimated recoverable reserves of 70.8 Bcm of gas and 4.8 MMt of gas condensate, lies beneath the Andean foothills. Photo: Gazprom.
Fig. 4. Incahuasi gas and condensate field, Total’s first operated development in Bolivia, was brought onstream in early August. The field, which has estimated recoverable reserves of 70.8 Bcm of gas and 4.8 MMt of gas condensate, lies beneath the Andean foothills. Photo: Gazprom.

Progress was made last year in Bolivia, as well. Incahuasi gas and condensate field (Fig. 4), Total’s first operated development in the country (50%), was brought onstream in early August. The field, which has estimated recoverable reserves of 70.8 Bcm of gas and 4.8 MMt of gas condensate, lies beneath the Andean foothills, about 155 mi from Santa Cruz de la Sierra. Total and its partners—Gazprom (20%), Tecpetrol (20%) and YPFB Chaco (10%)—reported that the field has a production capacity of 50,000 boed.

“Incahuasi is one of the largest gas and condensate fields brought onstream in Bolivia. Incahuasi’s production will contribute to Bolivia’s gas exports to Argentina and Brazil, as well as domestic consumption,” said Arnaud Breuillac, president of E&P at Total. “Delivered within budget, Incahuasi is the fourth start-up this year and, as a low-cost project with a long production plateau, it will contribute to the group’s production growth.”

By the end of September, Incahuasi field was producing commercially. Following the field’s first production stage—which included the construction of three wells, a comprehensive gas treatment unit, an in-field pipeline system, and a production control system—its daily output was reportedly expected to reach 6.5 MMcmg by year-end.


Following the inauguration of U.S. President Donald Trump, Mexico’s energy industry has faced mounting tension, as the nation relies heavily on the U.S. for its gas imports. Government data show that Mexico’s gas imports reached a record 4 Bcfgd last year.

The Trump administration has proposed a 20% tax on imports from the country, which would help fund the construction of an almost 2,000-mi wall to be built along the southern U.S. border. “By doing that, we can do $10 billion a year and easily pay for the wall, just through that mechanism, alone,” White House Press Secretary Sean Spicer said of the proposed tax. However, as Trump’s tax reform proposal was unveiled on April 26, it was unclear whether the administration would follow through on the border tax.

Additionally, Mexico is contending with the collapse of its oil reserves. Last month, Bloomberg reported that the country’s reserves could dry up in as little as nine years, if no new discoveries are found. The National Hydrocarbons Commission reported a considerable drop in reserves last year, from 10.24 Bbbl in 2015 to 9.16 Bbbl in 2016. Overall, proven reserves have declined 34% since 2013, due to Mexico’s record-low drilling activity.

To help revive Mexico’s ailing oil industry, President Enrique Pena Nieto announced that the Mexican government would auction off a strip of land near Tecpatán, in southern Mexico, to private drilling companies. This is the first opportunity for global oil majors to operate in Mexico, since the government took control of its energy industry almost 80 years ago.

The auction is scheduled to take place this summer, and the National Hydrocarbons Commission reportedly expects to raise up to $2.8 billion from onshore sales, alone. While 13 companies—including Total, Ecopetrol and Gran Tierra Energy—have already expressed interest, many Mexican citizens have been forthright with their opposition.

Despite the political uncertainty surrounding President Pena Nieto’s decision to hold a land auction, as well as that surrounding Mexico’s relationship with the U.S., some E&P activity has persisted. In March, Eni reported a discovery in the shallow waters of Mexico’s Campeche Bay. The Amoca-2 well reportedly represented the first well drilled by an international oil major in Mexico since the 2013 Energy Reform. The well, which reached a TD of nearly 11,483 ft, was drilled in the Contractual Area about 745 mi west of Ciudad del Carmen. It encountered approximately 360 ft of net oil pay from several good-quality Pliocene reservoir sandstones, about 213 ft of which were discovered in a deeper, previously undrilled horizon. According to Eni, the reserves are still being assessed.

Eni—which holds a 100% stake in the Area 1 PSA—reported that the Area-1 drilling campaign would continue with the Amoca-3 well, followed by the Miztόn-2 and Tecoalli-2 delineation wells. The wells are expected to be drilled this year.


Economically, petroleum has been a staple for Trinidad & Tobago’s export market since the collapse of its agricultural sector. The twin-island nation continues to strengthen its position in the industry through increased E&P activity.

To increase production from low-pressure wells in the Columbus basin, BP Trinidad & Tobago and Atlantic LNG have sanctioned the Trinidad Onshore Compression (TROC) project. The project, which received final approval in July of last year, will add an additional inlet compressor at the Point Fortin Atlantic LNG plant. It is expected to deliver approximately 200 MMcfgd. BP announced official start-up of the project in April. Bernard Looney, chief executive of BP’s upstream business, said, “Delivered on time and on budget, this major infrastructure project is part of BP’s plan to bring 500,000 bopd of new production capacity online by the end of 2017, and paves the way for Juniper, our other major project start-up in Trinidad and Tobago this year.”

BP’s Juniper platform reportedly set sail for Trinidad & Tobago (T&T) in January. One of its largest start-up projects in 2017, Juniper represents the company’s 14th offshore installation and its first subsea field development in T&T. The platform, as well as corresponding subsea infrastructure, will be installed 50 mi offshore, in about 360 ft of water. As a $2-billion investment, Juniper reportedly will have a production capacity in the region of 590 MMscfd.

LGO Energy has ramped up activity in T&T, as well. In February, the company began drilling operations at Goudron field. LGO said that it had been contracted to drill two infill wells at Goudron, targeting the Mayaro sandstone reservoir. The first well, H18E N4, will target a net 200-ft thick Mayaro sandstone pay interval, at depths between 300 ft and 1,000 ft.

While many operators are increasing activity in the region, Centrica opted to sell its entire portfolio of gas assets to Shell E&P in November. For an initial cash consideration of $30 million, Shell acquired a 17.3% interest in the producing NCMA-1 Block, as well as operated interests in two undeveloped blocks—NCMA-4 (80%) and Block 22 (90%). According to Centrica, the divestiture is in line with its strategy to focus its E&P acitivity in the UK, the Netherlands and Norway. wo-box_blue.gif


About the Authors
Emily Querubin
World Oil
Emily Querubin
Related Articles FROM THE ARCHIVE
Connect with World Oil
Connect with World Oil, the upstream industry's most trusted source of forecast data, industry trends, and insights into operational and technological advances.