Oil & gas in numbers

82.1 million b/d: Global crude oil and natural gas liquid production as of February 2010

11.8 million b/d: Total amount of global production as of February 2010 classified as heavy oil

b/d=Barrels a day. Source: Wood Mackenzie

Heavier crude grades are primed to play a more prominent role in meeting global demand for Middle Eastern oil. The region is not yet a hotspot for heavy oil extraction, compared to established giants such as Canada and Venezuela. Yet Middle Eastern reserves of discovered heavy and extra-heavy oil resources are estimated at 970bn barrels, most of which are undeveloped.

Maximising recovery and arresting natural production declines will require enhanced recovery techniques

Rick Penney, Schlumberger

To put it another way, Middle Eastern heavy grades account for 28 per cent of the world’s total recoverable oil reserves, Bahrain’s oil minister, Abdulhussain Mirza, told the Heavy Oil World Mena conference on June 2010.

If long-term global oil demand forecasts are realised, key producers, such as Saudi Arabia, Kuwait and Oman, will have to bring on stream more of the bitumen-heavy crude deposits that are harder and more expensive to extract and refine.

Heavy demand for oil

Prior to the 2008 global economic crisis, demand for heavier oil was growing strongly, triggering growing interest in developing these reserves. That year, notes consultancy Wood Mackenzie in a heavy oil study released in February 2010, global crude oil and natural gas liquid production reached almost 82.1 million barrels per day (b/d). Only about 11.8 million b/d of this was from sources at less than 28 degrees American Petroleum Institute (API) gravity, which is classified as heavy.

Saudi Arabia main producing fields*
Field Capacity (million b/d) Grade
Ghawar 5.0 Light
Safaniya 1.4 Heavy
Khurais 1.2 Light
Qatif 0.5 Medium
Shaybah 0.5 Extra Light
Zuluf 0.45 Medium
Abqaiq 0.4 Extra Light
*=By grade. Source: EIA, 2008-2009

Across the Middle East, there are successful heavy-oil developments under way, in Sudan, Egypt and Oman. New heavy-oil projects in Iraq and Iran could also make an impact.

“Most of the new projects in Iran would be heavy crudes by Gulf standards and Iraq has extensive heavy reserves, such as the East Baghdad field, as well as heavy zones within the existing medium or light fields,” says Sadad Husseini, a consultant and former head of exploration and production at Saudi Aramco. 

As heavy oil does not flow without stimulation, it is different from other types of crude production. This means international oil companies and oilfield services companies, such as Schlumberger, are in increasing demand as technology partners to help bring the heavy crude deposits on stream.

Kuwait has been negotiating with oil majors to help it meet a target of 270,000 b/d of production from heavy oilfields. In Kuwait’s Partitioned Neutral Zone, supermajor Chevron achieved first steam injection on a pilot steamflood project to help pump heavy crude from the Wafra field in June 2009. The $340m project is expected to lead to the first commercial application of a conventional steamflood in a carbonate reservoir anywhere in the world – injecting steam into heavy-oil reservoirs to heat the crude oil underground, reducing its viscosity and allowing its extraction through wells.

France’s Total also announced in April 2010 it was in talks with Kuwaiti officials to develop heavy-crude deposits from northern fields, using enhanced oil recovery (EOR) techniques.

Kuwait Oil Corporation (KOC) is looking to develop its extensive heavy oil resources in sandstones at Ratqa, in the north, with its first pilot steam soak wells and plans to inject to its first nine spot patterns by 2012. The aim is to start with an output of 50,000 b/d by 2015 before hitting full production by 2030.

Saudi investment in heavy oil

Saudi Arabia is further advanced than Kuwait with its major heavy-oil development, the 900,000 b/d offshore Manifa field, but has taken a relaxed approach to production schedules.

The $9.28bn project, which involves building a man-made causeway to 27 shallow-water drilling islands, will pump 900,000 b/d of heavy crude oil, 900 million cubic feet a day (cf/d) of associated gas and 65,000 b/d of condensate, along with new processing infrastructure to handle the volumes of sulphur-rich Arabian heavy crude.

Aramco appears increasingly committed to Manifa. Saudi sources told MEED in November that the company is considering plans to increase the capacity of the field from 900,000 b/d to 1.2 million-b/d, in the aim of adding 40 million cf/d of sour gas from the field.

The company expects to complete Manifa by 2015, about four years later than originally planned. Key construction packages on the development were not activated until early 2010, with drilling starting in March.

The decision to extend the completion date reflects the weaker oil demand since late 2008. In December 2008, with oil prices feeling the impact of the global recession, Saudi Arabia’s Oil Minister Ali al-Naimi said the production date for Manifa would depend on when the market needs more oil.

With the Organisation of the Petroleum Exporting Countries (Opec) restraining output, there is little pressing need to fast track heavier crudes, not least with the kingdom enjoying a massive spare capacity buffer. “The main reason for the delay at Manifa is the availability of 4-4.5 million b/d of spare capacity in Saudi Arabia alone,” says Husseini.

Saudi oil policymakers are adamant that the sanctioning of Manifa does not represent an admission that the future Saudi crude slate will be tilting heavier due to depleting light crude reserves. Rather, it is a sign that the kingdom needs to prepare new crude supplies to feed planned refineries.

Future Saudi crude exports will dominate by lighter grades, leaving the heavier volumes to be refined at home. All of Manifa’s capacity will be used domestically to supply two planned 400,000 b/d export refineries at Yanbu and Jubail.

Traditionally, heavy crude sources did not fit well with the processing capability of the global refining system, but this is changing. During the last two years, says Wood Mackenzie, more than 1.5 million b/d of grassroots refining capacity came on-stream, much of it in Asia Pacific, configured to process heavy crude. Over 1 million b/d of coking capacity is being added in the Middle East and Asia Pacific, a significant proportion of which is within grassroots refineries that are being designed to process heavy crude from the Middle East.

Heavy oil supply capacity

Wood Mackenzie forecasts a huge upside for the supply capacity of the Arab Heavy grade to be realised over the next decade, due to upstream investment in heavy crude producing fields. 

The growing appeal of heavy oil means Middle Eastern producers will need to beef up their technological toolkit. Since countries such as Venezuela, Mexico and Canada have been tapping heavy fields for decades, there is at least a knowledge bank that the region’s producers can tap into. “The production of heavy oils in the Middle East may be relatively new, but there is global experience on which to draw to improve overall recovery for these challenging fields, and importantly, to reduce their environmental footprint,” says Rick Penney, manager of enhanced oil recovery (EOR) Middle East projects at oilfield services giant Schlumberger.

EOR is central to many other countries’ heavy-oil development programmes. Although developments, such as the South Oman waterfloods in the Nimr area, and primary development of heavy-oil fields in Sudan, Egypt and Oman can be achieved using conventional extraction techniques, these typically only recover 5-15 per cent of the oil in place.

“Maximising recovery, arresting the natural declines in production and maximising the economic value of these assets – plus heavier fields currently without an economic option – will require enhanced recovery techniques,” says Penney.

“Major challenges in Middle Eastern heavy oil firstly are related to geology as heavy oil in carbonate (limestone) reservoirs differ from sandstone reservoirs elsewhere in the world. This is because they are often naturally fractured or contain other thief zones, and demonstrate very low permeability. Secondly, many carbonate reservoirs can be ‘oil wet’ – the oil preferentially stays attached to the rocks and so is harder to produce without EOR methods,” adds Penney.

Oman, blessed with more challenging hydrocarbon geology than its Arabian peninsula neighbours, has set the pace in pioneering the application of EOR techniques to unlock heavy oil deposits.

New technologies have made some of Oman’s more difficult heavy fields newly accessible. Petroleum Development Oman’s Marmul field, in the south of the country, is characterised by heavy crude oil that proved difficult to extract using traditional methods such as pumping or water flood. When it undertook a small-scale polymer flood pilot in this sandstone reservoir in the late 1980s, the method was considered uneconomic. But changed economic conditions have made the higher cost of using polymers more feasible.

There are other challenges beyond technology that regional producers need to take on board. Conventional Gulf crude does not need any special expertise in terms of upstream production. However, extra-heavy crudes in the low 18-22 degrees API range need steam injection and therefore gas to power the steam generation. “Gas is in short supply within the Gulf at low enough prices to encourage these steam injection projects, except in isolated EOR developments, such as in Oman,” says Husseini.

The higher costs of EOR developments must be factored into project economics, along with the supply of high-quality water for thermal and polymer projects, and gas for thermal fuel and miscible gas injection projects. 

Challenges ahead for heavy oil

“In heavy oil developments, it is not so much the raising of capital that is the main challenge, but balancing the significant capital requirements and oil price volatility by shortening the time to first oil, and reducing the potential risks associated with adopting certain recovery strategies,” says Penney.

“Both of these challenges can be met to a large extent by using a combination of the technologies and services to better evaluate and understand the reservoir and fluid characteristics, and how they may change through EOR or thermal processes over time. With accurate models, oilfield services companies can use continuous feedback to help NOCs to select, simulate, and adjust the most appropriate methods to meet their reservoir and financial drivers,” he adds.

As most heavy oil fields in the Middle East are onshore, they allow the ability to start small with pilot projects, gain confidence and then expand over time as results and cashflow allow. “This type of modular approach is a significant factor in reducing the levels of risk for each project: moving towards large-scale developments facilitates growth of experience before major financial commitments,” says Penney. 

The days of easy oil still have a long way to run in the Gulf, but the shifting global demand dynamic and growing comfort with EOR techniques could transform the region’s oil slate. Manifa is only the largest of the new heavy oil schemes that could prove to be game changers for the industry. From Sudan to Iran, producers are ready to tap into the more viscous oil reserves under their feet.