Wild ride

Brazil

Thanks to the wealth of its offshore presalt play, Brazil’s oil production had reached 3 million bpd by late 2019. Because the vast majority of the play is in deep water, state-owned Petrobras and its partners have largely relied on floating production, storage and offloading vessels (FPSOs) to produce the fields. During 2019, eight FPSOs were anchored into place, with the most recent, FPSO P-68, expected to reach full output of 150 000 bpd by mid-2020.

More vessels are planned. In December 2019, Petrobras signed a joint venture (JV) with Japan-based Mitsubishi to build an FPSO to service the Mero oilfield. The FPSO Sepetiba will be deployed in 2200 m waters 185 km off the coast of Rio de Janeiro.

Brazil also produces 4.5 billion ft³/d of gas, but most of it is associated with crude production in the Santos Basin. The majority is either flared or reinjected due to a lack of transportation options. Two gas lines connecting fields to shore are in operation, and a third, planned for completion in 2021, will bring network capacity to 1.6 billion ft³/d. Norway-based Equinor has agreed to build turbine electricity and LNG facilities in the Rio de Janeiro region to utilise the gas.

Guyana

Guyana’s deep water Atlantic continental shelf is one of the world’s hottest offshore plays. ExxonMobil and partners have made 15 commercial discoveries in the Stabroek block and have firmed up approximately 6 billion boe/d in proven reserves. Liza Destiny, a 120 000 bpd FPSO vessel, started production in December 2019. ExxonMobil estimates that there is potential for at least five FPSO vessels producing more than 750 000 bpd over the next decade.

Mexico

Mexico has six major refineries with a nominal capacity of 1.6 million bpd, enough to meet its domestic fuel requirements. Years of mismanagement and lack of maintenance by Pemex has lowered operations to 40% capacity, however, and the country must import half of its gasoline, diesel and jet fuel from the US.

Site preparation is well underway at the new Dos Bocas refinery in the state of Tabasco. President Andrés Manuel López Obrador justified the construction of the greenfield US$8 billion project as the cornerstone of his plan to return Mexico to fuel self-sufficiency. Pemex is overseeing construction of the 340 000 bpd refinery, but few observers expect the state-owned company to meet the government’s 2021 deadline for first production.

In mid-2019, Eni began first output from its Mizton field, located in the shallow waters of the Bay of Campeche, using a fixed offshore platform to extract 8000 bpd. The Italian company, which has identified over 2 billion boe (90% oil) in its Area 1 block, plans for two more fixed platforms as well as an FPSO. The vessel, under a 15-year contract, will have a capacity of 90 000 bpd, 75 million ft³/d of gas and 700 000 bbl of storage.

In October 2019, Pemex began operations at its Abkatun-A2 offshore production platform in the Bay of Campeche. The US$454 million platform, built by engineering firm McDermott International, replaced the original facility that was destroyed by fire in 2016. The new platform has the capacity to produce 220 000 bpd and 350 million ft3/d.

Ecuador

Ecuador, a member of OPEC, produces approximately 550 000 bpd of crude. In August 2019, state-owned PetroEcuador called for expressions of interest from international companies to build a new refinery to replace its ageing 110 000 bpd Esmeraldas complex. The 42-year old refinery has been undergoing extensive maintenance for the last several years, but the state-owned company has decided that it would be too costly to substantially reduce pollution levels. Government officials estimate that the new facility will cost approximately US$6 billion.

Argentina

The Vaca Muerta shale in Neuquen province in Argentina holds an estimated 16 billion bbl of crude and 308 trillion ft³ of gas. Although other areas in South America (such as Colombia) show great promise with unconventional resources, the Neuquen province has been producing hydrocarbons for the better part of a century and already has much of the skilled workforce, processing and pipeline infrastructure necessary to exploit the resource.

State-controlled YPF and international players have been sizing up the play for the better part of a decade. Shell has announced plans to drill over 300 wells, build a processing plant, and construct roads, powerlines and pipelines in order to move up to 40 000 boe/d by 2021. Chevron, Total and ExxonMobil have all announced billions in spending plans.

The fruits of investment are already being harvested. By the end of 2019, Vaca Muerta production had reached 100 000 bpd of crude and 1.1 billion ft³/d of gas. This has pushed domestic production to 514 000 bpd and 4.6 billion ft³/d. The country has approximately 550 000 bpd refinery capacity; demand for diesel and gasoline stands at just under 400 000 bpd. Refinery run rates have increased to almost 80%, which has resulted in the cessation of fuel imports and the rise of crude exports to over 45 000 bpd.

Baker Hughes has estimated that the Vaca Muerta oil and gas output could rise five-fold over the next five years with sufficient investment. To meet that goal, government officials have estimated that it would require US$10 – 15 billion annually for drilling and fracking, with another US$2 billion to build a gas pipeline and US$5 billion to build an LNG plant to allow exports. If the stars align, the Argentine government expects daily crude output to double to 1 million bpd by 2023.

Venezuela

Under President Chavez and his successor Nicolas Maduro, Venezuela has been going through a decade of woes that has seen its oil and gas sector and civil society decimated. In early 2019, Juan Guaido, president of the opposition-held National Assembly, appointed himself interim president. Numerous nations recognised his legitimacy. The Trump administration barred US customers from paying for Venezuelan oil until a new government can be formed.

OPEC claims that Venezuela produced an average of 1 million bpd in 2019, but industry sources say the figure is likely closer to 800 000 bpd. More alarming are the events occurring within Petróleos de Venezuela S.A. (PDVSA) itself. In 2017, after jailing former presidents on corruption charges, Maduro placed army officers with no experience in charge. As many as 30 000 veteran employees subsequently left, leaving very few experienced staff to run day-to-day operations.

As a result, PDVSA has largely handed over operations to JV partners such as Rosneft and China National Petroleum Corp. (CNPC) to keep fields running. Insiders have also noted that JV partners have taken on other major roles, including trading, procurement and shipping. Opposition members in the National Assembly have pointed out that the de facto privatisation is illegal. JV partners have also noted the futility of trying to operate fields without staff or logistical backup, and expect production to plunge further.

In March 2019, a prolonged electricity blackout that affected most of the country also crippled the downstream sector. Refineries, upgraders and export terminals, including the main port of Jose, were all idled. In October 2019, two of Venezuela’s major refineries were off for several weeks after a lightning storm knocked out power. The Amuay and Cardon units in the country’s massive 955 000 bpd Paraguana Refining Center eventually resumed processing at 40 000 bpd. Analysts estimate that domestic refining is operating at 33% capacity, causing extensive fuel shortages throughout the country.

Curaçao

A long-standing dispute over the 335 000 bpd Isla refinery and oil terminal on the island of Curaçao ended in late 2019 when the government’s state-owned RdK signed an agreement with Klesch Group to operate the 335 000 bpd facility. The dispute arose when US-based ConocoPhillips moved to seize assets of PDVSA, operator of the complex. The legal wrangling idled the plant. Klesch, which operates a refinery in Germany, will purchase the assets and take over operations from PDVSA.

Trinidad & Tobago

Trinidad & Tobago (T&T) has been a major LNG exporter for the last two decades, with a nameplate capacity of 14.8 million tpy (which consumes approximately 1.8 billion ft³/d). In 2019, it exported approximately 12.5 million t. The country’s long-term LNG export prospects are clouded by resource concerns, however. Since 2010, output has dropped by 25%, from 4 billion ft3/d to approximately 3 billion ft³/d, as ageing fields have depleted. BP, the major producer of offshore gas, has encountered disappointing results in several recent exploration wells, and may have to consider mothballing up to 20% of its LNG capacity.

Prospects for T&T’s idle Pointe-a-Pierre 160 000 bpd refinery improved in late 2019 when it was purchased by a company partly-owned by Trinidad’s labour union OWTU. The refinery was shut by the government in late 2018 after it was estimated to be losing US$300 million per year and would require up to US$1 billion to reverse the losses.

The new owner, Patriotic Energies and Technologies (Pet) faces several challenges in returning the refinery to full operations, including refurbishing and upgrading several key units such as the 40 000 bpd ultra-low sulfur diesel module. T&T’s crude output has also dropped to under 60 000 bpd, and Pet will have to import the majority of feedstock at premium prices.

Trinidad’s methanol sector will get a boost when the 1 million tpy CGCL plant at La Brea industrial park comes on-stream in mid-2020. The plant, jointly owned by Mitsubishi and state-run Massy Holdings, is guaranteed gas feedstock by National Gas Co. In addition to the US and Europe, the consortium is targeting Japan as a consumer.

Challenges

In Mexico, President Andrés Manuel López Obrador has largely halted the oil and gas reforms made by his predecessor Enrique Pena Nieto, cancelling licence rounds and championing Pemex at the expense of domestic and international explorers. Pemex is the most indebted oil company in the world, and rating agencies have downgraded Pemex bonds to junk and reduced Mexico’s credit rating, as well. Investors, faced with lower risk in other jurisdictions, are wary of further investment in the country.

In Argentina, an extended recession has caused rampant inflation and hiked borrowing rates. Many smaller exploration firms have idled rigs and reduced capital investment; with decline rates in shale wells averaging 70% over two years, production increases are in jeopardy. The government is working to shore up investor confidence by boosting domestic productivity and exports in order to reduce debt and balance the national budget. Until the oil industry sees an increase in economic stability, access to capital market and a reasonable rate of return, however, a cloud hangs over the longer-term prospects for the sector.

In Ecuador, public distrust of the government (fuelled by a corruption scandal involving the previous president and the botched renovation of the Esmeraldas complex) is hampering efforts to rebuild the downstream sector. Inequality between the ruling elites and the large indigenous population is also fomenting dissent that complicates efforts to modernise the economy.

Future

Not all is doom and gloom. Brazil’s new administration under President Jair Bolsonaro intends to streamline the sector by scaling back local content requirements (such as production ship building), increasing auctions, and opening up the upstream, midstream and downstream sectors to more competition.

Colombia is reaching out to international firms to inject cash into its oil and gas sector and build crude reserves. The government held two auctions in 2019 for onshore and offshore licences, generating approximately US$1 billion in licence fees and exploration commitments.

Clearly, Latin America holds great potential as its 650 million citizens move toward prosperity and increased energy consumption. Many jurisdictions, such as Brazil and Colombia, are making the necessary fiscal and regulatory changes to encourage investment in both exploration and infrastructure. But for oil and gas participants in countries like Venezuela, prospects over the next few years are less promising.

Written by Gordon Cope.

This article was originally published in the April 2020 issue of Hydrocarbon Engineering. View the full issue here and register to receive a free regular copy here.

Read the article online at: https://www.hydrocarbonengineering.com/special-reports/06042020/wild-ride/