The long road to recovery – GlobalData analyses recoverable reserves

Of the world's top 100 development projects assessed by GlobalData, 23 are located in Latin America, 20 in North America and the Caribbean, 15 in Africa, 14 in Asia-Pacific, ten in Europe, and nine each in the Former Soviet Union (FSU) and the Middle East.

The 20 projects in North America include shale plays in the US and Canada: Wolfcamp Shale, Marcellus Shale, Bakken Shale, Eagle Ford Shale, Utica Shale, Barnett Shale, Niobrara Shale, Tuscaloosa Marine Shale (TMS) and Monterey Shale.

The numbers game

The top nine upstream development projects in the FSU involve an aggregate capex of $297.9 billion, of which almost half will be invested in the Kashagan field development in Kazakhstan. The Kashagan field, which has remaining oil and gas reserves of around 8.4bboe, has seen upwards cost revisions several times. Other major FSU projects involving high capex include Shah Deniz and Azeri-Chirag-Guneshli (ACG) in Azerbaijan, at $34 billion each.

Latin America and Asia-Pacific follow the FSU in terms of regional capex, at $233.8 billion for Latin America and $189.9 billion for Asia-Pacific. Projects involving high capex in Latin America include the Lula field at $61.7 billion, the Franco field at $29.5 billion and the Carabobo-1 field at $23.9 billion. In Asia-Pacific, key projects involving high capex are Greater Gorgon at $54.5 billion, Ichthys at $34.4 billion and Asia-Pacific Liquid Natural Gas (APLNG) at $25.6 billion.

Among the major upstream development projects, six have capex of $50 billion or more, 11 have capex of $21-49 billion, 18 have capex of $11-20 billion and 22 have capex of $5-10 billion. In terms of remaining recoverable reserves of oil and gas, five projects have reserves of 10bboe or more, seven have reserves of 5-9bboe and 20 have reserves of 2-4bboe. The Petrobras-operated upstream projects considered in the report involve an aggregate capex of $148.8 billion.

Among the projects, Petrobras operates the most assets, with eight, followed by Chevron and BP, at six and five respectively. Six of the Petrobras-operated assets (Cernmabi, Franco, Jubarte, Lula, Marlim Sul and Roncador) are located in Brazil's pre-salt areas in the Santos and Campos Basins, and the remaining two, the Sabalo and San Alberto fields, are in Bolivia.

The Chevron-operated assets are Greater Gorgon in Australia, Gendalo-Gehem in Indonesia, Manatee in Trinidad and Tobago, Rosebank in the UK, Lianzi in Angola and El Trapial in Argentina. The BP-operated assets are Azeri-Chirag-Guneshli (ACG) and Shah Deniz in Azerbaijan, Khazzan in Oman, the North Alexandria Concession in Egypt and Clair in the UK.

Of the major projects considered in the report, Saudi Aramco operates the largest remaining recoverable reserves, at 39.9bboe. This is accounted for by the Khurais, Manifa, Al-Wasit and Karan fields, which have remaining recoverable reserves of 19.4bboe, 13.7bboe, 4.0bboe and 2.9bboe respectively. Petrobras and Anadarko operate reserves of 17.7bboe and 13.7bboe respectively. Some of Petrobras' major development projects include Lula, Franco and Roncador fields, while Anadarko operates the Rovuma Area 1 project.

North Caspian Operating Company's upstream projects have the highest aggregate capex among the reported projects, at $149.5 billion. The company operates just one upstream project referenced in the report: Kashagan.

World Expro shines a light on six of the major projects around the world.

Asia-Pacific: Greater Gorgon, Australia

The largest energy project in Australia, the Greater Gorgon project comprises a series of offshore gas fields with a combined gas resource of 42 trillion cubic feet (tcf). The $54.5-billion project comprises a 15 million metric tons a year onshore LNG facility, two production platforms, 30 development wells, and the world's largest CO2 sequestration facility, and is due to come online in 2016.

Chevron has a 47.3% equity stake and is the operator of the project. The other equity partners in the project are ExxonMobil with 25.0%, Royal Dutch Shell (Shell) with 25.0%, Osaka Gas Company with 1.3%, Tokyo Gas with 1.0%, and Chubu Electric Power with 0.4%.

The natural gas fields in Greater Gorgon are located in the Rankin Platform, and the Exmouth and Barrow Sub-basins of the greater Carnarvon Basin. The Gorgon field accounts for 60% of the reserves in the Greater Gorgon area. Structurally, Gorgon is a graben, bounded by a series of normal faults that create structural traps and seals, isolating the Gorgon gas field from the surrounding geology.

Greater Gorgon project encompasses development of Gorgon, Jansz-Io and several other smaller gas fields in the Greater Gorgon area. The Gorgon and Jansz-Io fields are located 80-140 miles (130-220km) from the north-western coast of Western Australia.

Development of the Great Gorgon project involves building offshore infrastructure like subsea wells and pipelines, as well as a gravity-based platform to consolidate gas produced from the fields and transport it to the planned LNG facility, on which construction started in 2009. It will be located in the Borrow Island, and shipments of LNG are expected to commence in 2015, postponed from the initial 2014 date.

The Greater Gorgon project is currently under development, despite a capex rise from the original $37 billion to around $54 billion, due to reasons such as the strengthening of the Australian dollar and increased labour costs. If the project continues to face cost issues, its financial viability will be at serious risk.

The Franco oil field is located 130 miles (210km) south of Rio de Janeiro, in offshore Brazil. It is a pre-salt deepwater field in the Santos Basin, at a water depth of around 6,550ft (2,000m). Petrobras has a 100% equity stake and is the operator of the field.

According to Brazil's energy regulator, the National Petroleum Agency (Agência Nacional do Petróleo, ANP), the Franco pre-salt field could hold 8-12 billion barrels, and could be equal to or larger than the size of the giant Libra field.

Latin America: Franco, Brazil

The Franco field was discovered in May 2010, when the 2-ANP-1-RJS well produced high quality oil of 28-30° API. Petrobras is currently undertaking testing at the field. The reservoir rock of the Franco field includes microbial carbonates of a sag sequence, along with limestone coquinas formed during a syn-rift sequence.

For the development of the Franco field, Petrobras has awarded contracts to UTC Engenharia, Norberto Odebrecht and OAS, for the conversion of four very large crude carriers - P-74, P-75, P-76 and P-77 - into FPSOs. The conversion work started in June 2011 at the Inhaúma Shipyard in Rio de Janeiro, and all four FPSOs will have a maximum production capacity of 150mbd.

Petrobras will use P-74, P-75, and P-77 for production at the Franco field, and P-76 at the Franco Sul field. Production at the Franco field is expected to begin in the second half of 2016, while P-76 production is expected to begin in the second half of 2017.

Development of the Franco field involves several challenges, including high well costs, which are currently estimated at around $66 million. Moreover, the wells are prone to salt creeping and hydrate formations - caused by mixing hydrocarbons with produced water at high pressures and temperatures - leading to well closure or blockages of the production system.

The field development will also involve the setup of carbon capturing or CO₂ reinjection capabilities, as Brazil's environmental constraints do not allow the venting of large quantities of CO₂ into the atmosphere.

North America: Wolfcamp Shale, US

Wolfcamp Shale is an emerging liquids-rich unconventional play in the Permian Basin, in western Texas and south-eastern New Mexico. It is suitable for companies that want to focus on liquids-rich plays, as natural gas prices remain relatively low in the US. Some of the key operators of the play are EOR Resources, Approach Resource, Cimarex Energy, Devon Energy, Pioneer Energy and Linn Energy. The Wolfcamp Shale formation is 200 miles (322km) wide and 100 miles (161km) long, with depths of 7,000-10,500ft (2,134-3,200m). Its net pay thickness is 20ft (6m), and its porosity value is 9-12%.

Wolfcamp Shale has three zones, of which the top and bottom zones are productive. The thickness of the zones is estimated to be 1,200ft (366m), and the bottom zone is the most productive of the three, with 4-45ft (1.2-13.7m) of organic limestone and a subsea oil water contact at 5,370ft (1,637m). Though Wolfcamp has long been known to hold oil and gas, it remained mostly unproductive until the mid-to-late 2000s, owing to its low permeability. However, with the development of vertical drilling and hydraulic fracturing, production from Wolfcamp Shale has increased rapidly.

Today, Wolfcamp is one of the most active shale plays in the US; in 2013 alone, hundreds of wells were drilled in the shale, and the development densities have 40-140-acre spacing. Among the companies operating in the shale, Pioneer Energy has the largest net acreage, at 935,800 acres in the Midland Basin. Pioneer Energy also has one of the largest rig counts in the shale, at ten rigs. In 2012, it drilled more than 400 vertical wells.

The challenges faced by the companies operating in Wolfcamp Shale are a lack of proper infrastructure and high operational costs. Pioneer Energy has insufficient water resources in the Midland Basin and high electricity costs, effecting the profitability of the company. Other problems at the shale include inconsistent rock lithology and increasing environmental regulations in the Permian Basin.

Africa: Rovuma Area 4, Mozambique

Rovuma Area 4 is part of the Rovuma Basin in Mozambique. It is located 1,242 miles (2,000km) north of the Mozambique capital, Maputo, in ultra-deep waters at a depth of 8,530ft (2,600m). Eni, its operator, has a 50% stake in the block. China National Petroleum Corporation (CNPC), Galp Energia, KOGAS and Empresa Nacional de Hidrocarbonetos (ENH) are the other stakeholders in the project, with 20, 10, 10 and 10% stakes respectively.

Eni obtained a licence for exploration in Rovuma Area 4 in 2006, and the company made two significant discoveries in the block in 2011, with wells Mamba South 1 and Mamba North 1. In 2012, the company made another discovery at the Coral 1 well, as well as gas discoveries at Mamba North East-1 and Mamba North East-2. In total, the block has witnessed ten discoveries.

Current estimates for recoverable reserves from the block are about 75tcf and are expected to increase considerably with the ongoing appraisal programme. The Mozambican coast is described by rift, margin sag and passive margin rocks. The trap types at the Rovuma Area 4 include salt structures, flower structures, drape anticlines, tilted fault blocks and horsts. The existence of a wide variation of plays with significant resource potential is considered to be due to a combination of various reservoirs and source rocks.

The Rovuma Basin area consists of reservoirs of the Jurassic and Cretaceous period, along with indications of the presence of high-quality reservoir rocks in Upper Cretaceous-Lower Tertiary fan systems. Eni estimates that the investment required for the development of Area 4 could be as high as $50 billion. The proposed development infrastructure will include offshore hub facilities, tied back to an onshore LNG plant via subsea wells and long-distance pipelines.

In order to save costs, Eni plans a possible unitised development with the Anadarko-operated Rovuma Area 1 Block, which is located adjacent to Rovuma Area 4. The company is also planning to sell part of its equity stake in order to decrease risk and raise funds for the development of the project.

Aside from the investment risk, the development of gas infrastructure in Mozambique presents major challenges, as the country lacks basic infrastructure. Additionally, by the time Area 4 starts production, the global LNG market could see an intensely competitive situation, due to increasing supplies from countries like the US, Canada and Australia. This might result in downward pressures on LNG prices, increasing risk for the Area 4 project.

Middle East: Khurais, Saudi Arabia

Khurais is an oil, gas and condensate field located 155 miles (250km) south-west of Dhahran, Saudi Arabia, and is one of the largest conventional oil fields in the world. The crude oil and recoverable natural gas reserves are about 18.2 billion barrels and 6.8tcf respectively. Saudi Aramco is the operator, with a 100% equity stake.

Khurais is located in a large anticline found within the wider Arabian graben known as En Nala; the geology is described by a large north-trending anticlinal structure, expressed on the surface by outcrops of Cenozoic-era rocks. The vertical thickness of the reservoir at the field measures 280ft (85m) on average.

The field's average drill depth is 6,000-7,000ft (1,800-2,100m), and the field produces crude with an average API of 32°. The project includes the development of Khurais and the smaller Abu Jifan and Mazalij fields.

The Khurais project is one of the largest oil development projects in the world. Discovered in 1956, with initial production beginning in 1959 but suspended in 1961, it was redeveloped in 1970 with a production rate of 40mbd. 80 wells were drilled in the project by 1981, reaching a 144mbd production rate, but the project was again mothballed in the mid-1980s due to the lack of homogenous lithology of the reservoir and problems connected with the oversized gas choke valves.

In 2004, the plans were again initialised for the development of the field, and the process officially restarted in 2006. Between 2006 and 2009, 12 drilling rigs ran simultaneously, drilling approximately 300 wells. The Khurais central processing facility was also constructed, in order to process crude.

A major challenge for the operation of the Khurais field is the need to increase the recovery rate of crude. Khurais is a giant oil field, and even a 1% increase in recovery rate would result in millions of additional barrels. Security is also a problem here, though the Saudi Arabian government and Saudi Aramco provide proficient security services.

Europe: Troll, Norway

Troll is an offshore oil and gas field located in the northern part of the Norwegian North Sea, 40 miles (65km) west of Kollsnes, Norway. Statoil has a 30.6% equity stake and is the operator of the field. Petoro (56.0%), Shell (8.1%), Total (3.7%) and ConocoPhillips (1.6%) are the other equity stakeholders.

Troll has significant oil and gas reserves; the remaining crude oil and recoverable natural gas reserves at the field are about 274.5 million barrels and 28.8tcf respectively. Troll is located on the Horda Platform, on the edge of the Viking Graben Basin. The field's geological structure is defined by two tilted fault blocks, the clean sandstones of which are of excellent reservoir quality. The interbedded siltstones and mudstones are hydrocarbon bearing, but are largely non-producible due to low permeability.

The Sognefjord Formation, dating to the Upper Jurassic period, acts as the primary reservoir at Troll East and West. Oil produced at the field is low in sulphur content and has a medium API of 35.9°. Although Troll was discovered in 1979, monetisation of the field was delayed due to a lack of technology for the extraction of oil from thin pay zones. The development of multilateral wells enabled this extraction, and now 28 of Troll's 115 subsea wells are multilateral.

The field started supplying hydrocarbons to the market in 1995. Troll A started production in 1995 from Troll East, while Troll B and C started production in 1999 from Troll West. Troll A is a fixed concrete deep platform that primarily produces gas; Troll B is a semi-submersible with a concrete hull; and Troll C is a semi-submersible with steel hull. The B and C platforms primarily produce oil.

Troll has witnessed several new developments in the past few years, including modifications in 2011 to produce more oil from Troll West through gas injection methods, and the awarding of a contract in 2011 for the construction of a new pipeline from the Troll A platform. Two compressors, Troll 3 and Troll 4, will be installed in 2015, at a total cost of $1.8 billion. The compressors are expected to extend the life of the project until 2063.
The remote location and harsh climatic conditions of the North Sea prove challenging to the field, increasing risk and cost of maintenance. The geology of the field also requires the drilling of horizontal wells, which makes drilling more challenging and expensive than conventional vertical wells.