The oilfields of the Middle East are arguably some of the most agreeable in terms of production, with most being extremely large reservoirs containing easy-to-access hydrocarbons. 

This geological good fortune has meant that for several decades the region’s major oil producers have been able to use primary recovery techniques to extract oil and gas. Enhanced oil recovery (EOR) has only recently been contemplated and only by smaller producers with smaller fields, such as Oman.

In the Middle East… many national oil firms realise that primary production is not a sustainable option

However, there is a trend emerging in the Middle East where many national oil companies (NOCs) realise that primary production is not a sustainable option. This has led most to curb new exploration and instead adopt techniques traditionally used searching for new hydrocarbon resources to accurately map current assets and identify where best to introduce EOR.

EOR covers a range of techniques designed to increase the amount of crude extracted from a field and is also known as tertiary recovery. EOR allows 30-60 per cent or more of a reservoir’s original oil to be extracted, compared with the 5-20 per cent typically achieved using primary and secondary recovery techniques.

Pioneer of EOR

Oman is often cited as the pioneer of EOR in the Middle East and the sultanate’s hydrocarbons industry is working to wring every available drop of oil out of the ground.

Much of Oman’s reserves have now gone past primary and secondary production, which only requires water to be pumped into the fields, and has moved on to EOR.

In 2000, only 1 per cent of Petroleum Development Oman’s (PDO’s) oil output was produced using tertiary methods. This figure had jumped to 16 per cent by 2011 and will climb to 36 per cent by 2018. Thermal EOR and gas injection will be the two main methods.

PDO is investing billions of dollars on three onshore projects that it says will maintain its capacity of 550,000 b/d.

In March, the UK’s Petrofac was awarded a $1bn contract to carry out field works at the Rabab Harweel Integrated Project (RHIP).

Located in the Harweel cluster of onshore fields, RHIP will include sour gas processing facilities, associated gas injection systems and export pipelines.

It will handle the production of oil and gas from the Harweel oil reservoirs using miscible gas injections and the production of gas with condensate from the Rabab reservoir through the partial recycling of sour gas.

The complex has the capacity to export 4.9 million cubic metres a day (cm/d) of sweet gas and 9,700 cm/d of condensate in addition to about 16 million cm/d of high-pressure sour injection.

PDO also plans to tender similar-sized schemes at Yibal Khuff and Budour. The new projects will develop nearly 200,000 b/d of new capacity, offsetting the natural decline of the sultanate’s oil fields.

Tertiary commitment

By the end of 2012, Oman’s commitment to its oil fields was paying off, with production rising to 922,000 b/d, after dropping to 715,000 b/d in 2007.

However, the main challenge for Muscat will be to maintain its EOR programmes, while feeding turbines for the additional power required at the fields with limited access to natural gas.

After years of primary oil production, Kuwait Oil Company (KOC) has been implementing a series of water injection projects. In 2011, South Korea’s GS Engineering & Construction was awarded a $545m deal to build facilities that would enable 1 million b/d of water to be injected into the Wara oil formation to maintain pressure and production levels at Burgan, the world’s second-largest oil field.

The facilities include 10 water treatment units, 20 tanks, 60 pumps and up to 700 kilometres of pipelines.

KOC is also on the verge of awarding contracts on another scheme worth almost $1bn that aims to provide pressure support for the Sabriya and Raudhatain fields in the north of Kuwait by the end of 2017.

Dubai-based Dodsal Group is the lowest bidder for an effluent water treatment and injection plant to boost crude oil production at the two fields. The plant will have a capacity of 500,000 b/d and collect waste water from four oil-gathering centres in northern Kuwait.

After treatment, the water will be injected into 150 wells using about 250km of pipelines of 6-30 inches in diameter. It also includes storage tanks and pumps.

Heavy oil extraction

A slightly different take on EOR is also being planned for Kuwait’s $4.2bn development of the Lower Fars reservoirs.

The fields contain highly viscous heavy oil and, therefore, will require cyclic steam stimulation (CSS) to enable production. This technique involves steam being injected into the reservoir to heat the oil, thereby making it easier to pump to the surface.

This type of advanced EOR is still not needed for Iraq’s super-giant fields, but they have suffered decades of underinvestment and are now starting to see major rehabilitation take place. International oil companies (IOCs) operating in the Gulf state need to work hard to hit the pre-agreed production targets, which means investment on several fronts.

Seawater injection

Many of the major fields in southern Iraq are set to see billions of dollars spent on upgrade works that will include seawater injection facilities.

The key to these plans, however, is the $10bn Common Seawater Supply Facility (CSSF) project. The scheme involves the construction of a giant seawater treatment facility and pipelines. The US’ CH2M Hill is carrying out the project management consultancy after being awarded a deal for the first phase of the CSSF in May 2013 by the state-owned South Oil Company of Iraq.

The first phase will have a capacity of 5.2 million b/d of seawater that will be made available for injection. The plant will have a capacity of 12.5 million b/d when fully operational.

The water will be utilised by five fields in southern Iraq: Zubair; Rumaila; West Qurna-1; West Qurna-2; and Majnoon. Further phases will increase supplies to these fields as well as to the Gharraf, Halfaya and Missan oil fields.

Despite the scheme being a major priority for Baghdad, there has still been no award made for the front-end engineering and design. Oil and gas executives operating in Iraq say that unless a decision is made soon, 2017 production targets could be missed.

Private facilities

The delay to the CSSF scheme has not stopped IOCs from pushing ahead with their own water injection infrastructure.

The consortium for the Rumaila oilfield, headed by the UK’s BP, is tendering contracts to build water-processing facilities that it hopes will push production at the field to 2.1 million b/d by 2017.

Achieving this will involve ramping up water injection from current levels of 500,000 b/d to more than 8 million b/d. To realise this figure, three packages are planned under the produced water reinjection project (PWRI), a relatively short-term solution that aims to provide water for reinjecting into the field for the next 10 years.

Water will be gathered from the degassing stations and transported to new produced water treatment facilities. The treated water will then be pumped through infield pipelines to reinjection facilities.

Russia’s Lukoil is also tendering a similar scheme for the West Qurna-2 oil field. International contractors are bidding for a $1bn-plus water-injection and oil-gathering systems with an award expected to be made by the end of 2014.

Three phases of the water injection system are planned with phase one providing water until the end of 2015, phase two until 2019 and phase three up to 2035.

These investments demonstrate that the current focus for the region’s NOCs is to prop up ailing production rather than intensify exploration activities.

This means the next decade promises to continue offering opportunities for oil and gas companies, but EOR will be the priority. When production from these mature fields is secured for the medium terms, only then will the focus shift back to finding new sources of hydrocarbons in more complex and harder-to-access formations.