Abu Dhabi’s Oil Field CCS Projects Face More Delays

Abu Dhabi’s Oil Field CCS Projects Face More Delays

During confusion over CO₂ pricing and uncertain EOR projects, majors have to negotiate for ADCO concession renewal.

Abu Dhabi has delayed further its carbon capture and storage (CCS) scheme, which it says will be the world’s largest. The emirate’s Masdar clean energy initiative received in December engineering procurement construction (EPC) bids to build a 49km, carbon dioxide pipeline from a steel plant to Rumaitha onshore oil field. But it still has not awarded the contract, MEES learns, despite the front end engineering design (FEED) being finished in September last year. The project is unlikely to be operational before 2015.

Two other originally planned carbon capture sites – Taweelah power station and BP’s proposed hydrogen power plant – have been indefinitely delayed, Abu Dhabi sources tell MEES. The 49km pipeline is the only part of the planned 600km network of CO₂ pipelines that has got off the ground to date. The pipes would range in diameter from 8-inch to 14-inch and connect 17 CO₂ producing power stations and industrial sites to state-owned Abu Dhabi National Oil Company (ADNOC) oil fields including Rumaitha and Dabbiya (which together are called North East Bab), Bab and Bu Hasa. The project has been dramatically scaled back and the number of sites to supply CO₂ is under study.

ADNOC’s subsidiary Abu Dhabi Company for Onshore Oil Operations (ADCO) – which aims to boost its crude output to 1.8mn b/d by 2019 - does, however, plan a CO₂ pilot scheme at Habshan oil field, reinjecting waste gas from the field (MEES 19 September). It has carried out a previous similar, and successful, CO₂ trial in Rumaitha.

A major factor holding up Masdar is disagreements over pricing of power and CO₂. BP’s $2bn, 400mw, hydrogen power plant, which would produce CO₂ for oil field injection and hydrogen for burning, cannot go ahead unless its operators know how much they will be paid for the power and CO₂. “No one wants to pay for CO₂,” an Abu Dhabi insider tells MEES. “They’re building that massive nitrogen plant (MEES, 19 September) so who needs the CO₂?” he said.

However, ADNOC Director General 'Abd Allah Nasir al-Suwaidi’s taking over the company this year has raised hopes that he will set a workable CO₂ price. He is also on the board of Masdar. “When he became a board member it was a big coup for Masdar because they knew he would one day take over ADNOC,” an Abu Dhabi source tells MEES.” Former ADNOC chief Yusuf bin ‘Umair bin Yusuf was totally opposed to buying CO₂ for the projects.

First Project

In the commercial project that is most likely to come on stream first, state-owned Emirates Steel Industries (ESI) will give its CO₂ free to Masdar, a subsidiary of state-owned conglomerate Mubadala, a Masdar official tells MEES. Masdar will sell it to ADCO to fund the pipeline project. ADCO will gain by having more sales gas that is currently being reinjected – in a typical CO₂ injection project 3-5 tons of natural gas are recovered per 100 tons of CO₂. The steel plant project plans to send 800,000 tons/year of CO₂ to Rumaitha, which would potentially free 1.1-1.9bn cfd of gas if the field reinjected this much. Abu Dhabi’s total of reinjection gas is 3.3bn cfd, and during peak summer power demand ADNOC has had to drop oil production to provide sales gas to power stations. Furthermore ADCO would benefit from boosted oil production through enhanced oil recovery (EOR) – typically 3-6 tons of CO₂ liberate 10 barrels of oil. In optimal conditions CO₂ can lift total oil in place recovery by 20%, CO₂ compressor manufacturer Mitsubishi tells MEES, although a typical project usually achieves 5-10%. Rumaitha produces about 65,000 b/d and Bab, excluding NE Bab, produces about 420,000 b/d. ADCO is installing three gas compressor stations, totaling 1.8bn cfd, in Bab, which will be fully operational by mid-2012, a contractor tells MEES. “The stations are to extend field usage – it’s depleting. There’s more condensate than oil these days,” he says.

Some of Abu Dhabi’s fields are favorable for CCS – large, low-cost, onshore, and reasonably close to CO₂ sources, in a country which suffers from a severe gas shortage and desperately needs the reinjection gas for power generation. If has faced peak demand deficits of 2bn cfd. However, not all fields have optimal conditions – deeper than 800ms, and temperature greater than 20-40°C. In these conditions CO₂ forms a supercritical liquid which has properties of both oil and gas. It can be miscible with oil, lowering its viscosity and making it swell, pushing it towards the production wells. CO₂ can also scrub out residual oil that has migrated through rock on its way to a reservoir during the reservoir’s formation.

ADCO – ADNOC (60%), Shell, Total, BP and ExxonMobil (9.5% each) and Portugal’s Partex (2%) – has a concession to manage most of Abu Dhabi’s onshore oil fields, which expires in January 2014. Abu Dhabi is asking majors to pitch for concessions without knowing the results of pilot schemes, or the costs and volumes of CO₂. The Bab contractor tells MEES that the gas compression project he is involved in does not take any CCS project into account. Furthermore, when ADNOC commissioned Tracs International, a UK-based consultancy, for a technical assessment of its onshore field development projects (MEES, 16 May) – to gain more information before it takes a decision on concession renewal, it did not include CCS in its plans. But the report’s assessment of field plateau levels agreed with ADCO partners’ field expectations, so its findings will not hold up further the concession decision.

Adding to the confusion, Masdar may take operational control of some CCS schemes – at least the above ground CO₂ transportation and production  –  so  that  uncertainty  is  also  holding  up  projects  such  as the Rumaitha pilot scheme. In parallel to the Tracs International report, which was completed this summer, ADNOC has commissioned from Houston-based consultancy Ryder Scott a commercial assessment of its onshore fields and the ADCO consortium. Ryder Scott’s report will include, if the concession should be broken up, each of its fields separately awarded to individual operating firms. The CCS question would still hang over them. 

Abu Dhabi’s indecision is frustrating its ADCO partners, which have to pump capital expenditure into projects that they may have to relinquish. It has been telling them for nearly three years that a decision will be made “this year.” The result is the slowing down of field developments.

Lack Of Integration

Masdar’s other ‘Achilles heel’ is the lack of regulatory agreements and integrated policies. Abu Dhabi is forging ahead with a massive power plant building program – it expects peak power demand to soar from 11.3gw now to 22.9gw in 2020 – without specifying that future power plants are to be CO₂ capture ready. South Korea’s Samsung C&T Corp announced on 20 September that it has won a $579.3mn contract to build a 1gw power plant for Emirates Aluminium – a heavy CO₂ producer on Masdar’s original CCS projects list. But the plant is not being fitted for carbon capture. “Power station operators have the objective of low cost power, whereas Masdar’s a one-off thing,” Robin Mills, a UAE-based petroleum economist and author of Capturing Carbon, tells MEES. Combined-cycle natural gas plants lose efficiency from up to 57% to a maximum of about 53% when fitted with capture technology, due to the energy needed to capture the carbon.

If Abu Dhabi had a more coordinated plan it would build capture-ready plants, reducing costs when compared with retrofitting with a carbon grabber. Two options are pre-combustion plants, which remove carbon from the fuel before it is burned and are more efficient (47-53%) than post-combustion plants, which strip CO₂ from waste gases (45-49% efficiency).

However, pre-combustion plants resemble chemical plants, and would be purpose-built in the same way as a hydrogen plant. Mr Mills says: “There are only about 20 in the world today, they break down more often than post-combustion plants, few people know how to operate them and they are all coal-fired.” Abu Dhabi’s planned fossil fuel plants are all gas-fired, although it is not clear where the emirate will source the extra gas it needs for them. And if it fitted new plants with carbon capture technology it would drive the demand for gas even higher, due to the plants’ higher energy needs.

Another project that Masdar appears to have overlooked is the Shah ultra-sour gas field, which will produce about 100mn cfd of waste gas CO₂ from 1bn cfd of well-head gas. It will not be operational before 2015. Bab oil field is nearby, but there are no plans to pipe Shah’s gas into it. Shah is operated by state-owned GASCO – ADNOC (68%), Shell (15%), Total (15%), and Partex (2%). GASCO also operates the Habshan gas field – which also produces 200,000 b/d of condensate – where a massive nitrogen flood project is planned. The company would face the same commercial problems as ADCO if Masdar decides to go for CO₂ injection in an enhanced gas recovery (EGR) program.

Masdar’s grand plan of 7% of its electricity by 2020 to be produced from renewable power does not look in good shape either – so far its only significant power generation projects are two 100mw solar power plants.

A success for Abu Dhabi in CCS, however, could trigger more CCS projects in the Gulf – saving much needed gas in Saudi Arabia, Iran, Oman and Kuwait, and stabilizing maturing oil fields’ output in Qatar. The latter, whose LNG and GTL plants are equipped with carbon capture technology, is studying CO₂ injection into its swing producing Maersk-operated al-Shaheen oil field (MEES, 11 October 2010). Maersk, which has a CO₂ shipping fleet, is a world leader in CO₂ transport. Saudi Arabia is studying CCS use in Ghawar. It led the OPEC switch from opposing CO₂ reduction initiatives to campaigning for the UN to accept CCS as a recognized tool in fighting climate change.

Copyright MEES 2011.