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4.5 Carbon dioxide storage

Incentives to store carbon dioxide as a route to reducing the level of anthropomorphic carbon dioxide in the atmosphere, as opposed to using it as a working fluid for EOR operations, have only recently been formulated.

4.5.1 Deep saline formations

4.5.1.1 Sleipner

In 1996, Statoil and their licence partners started to inject 1 million tons of carbon dioxide per year into sands of the Utsira Formation at the Sleipner Field in the North Sea. The Sleipner West carbon dioxide facility comprises two main installations, the Sleipner B wellhead platform on the field and the Sleipner T treatment platform, adjacent to the Sleipner East facilities. Sleipner T is linked physically to the Sleipner A platform by a bridge. Other major component parts of the development include a 12,5 km flow line between the two. The wellhead platform is remotely operated from the Sleipner A control room via an umbilical line.

Amine scrubbing technology is used to remove carbon dioxide from high pressure natural gas. The carbon dioxide extracted is injected using a four-stage carbon dioxide injection compression system directly into the Utsira Formation 1 000 metres beneath the seabed. The Utsira Formation is a 200–250 m thick massive sandstone formation located at a depth of 800–1 000 m. It is estimated that the Utsira Formation is capable of storing up to 600 billion tonnes of carbon dioxide.

The carbon dioxide is injected into a small ‘structural closure’; when the closure has been filled, the carbon dioxide is expected to spill towards the north, and thereafter to the northwest. This is the first case of industrial scale carbon dioxide storage in the world. As such, monitoring of the behaviour of the carbon dioxide storage facility was necessary, in part to validate the computer models on which the safety case had been built, and also to serve as a basis for the injection of carbon dioxide into other deep saline formations in the future. Statoil initiated and organised a multinational and multidisciplinary research project that collected relevant data, then modelled and verified the distribution of the carbon dioxide ‘bubble’ for three years, and developed and demonstrated prediction methods for the destiny of the carbon dioxide for many years into the future.

The project, which was co-funded under the EU Saline Aquifer CO2 Storage( SACS) programme, has served as a test case for offshore underground carbon dioxide disposal in general, and for possible future use of the wide-spread Utsira Formation in particular.

3D seismic data covering the Sleipner East area has been used to map the Utsira Formation. The seismic response represents the changes in ‘impedance’ in the water-filled reservoir. The impedance is affected by the carbon dioxide injected into the reservoir, and is apparent on new seismic data produced. The presence of carbon dioxide and the movement of the carbon dioxide gas in the Utsira Formation reservoir can therefore be monitored by examination of later seismic data.

The computer predictions have been validated, giving confidence that the movement of carbon dioxide can be predicted with some confidence. Experiences gained have led to the production of a ‘best practice’ guide being published for the storage of carbon dioxide in deep saline formations60.

4.5.1.2 Snøhvit

The Snøhvit field is located in the Barents Sea in the central part of the Hammerfest basin, at a sea depth of 310–340 metres. Snøhvit is a gas field with condensate and an underlying thin oil zone. The field comprises several discoveries and deposits in the Askeladd and Albatross structures in addition to Snøhvit, and will eventually comprise 19 production wells and one injection well for carbon dioxide.

The unprocessed product, containing a mixture of natural gas, carbon dioxide, natural gas liquids and condensate, is transported through a 143 km pipeline to the processing plant at Melkøya. The gas is processed and cooled down to liquid form (LNG), the carbon dioxide (found between 5 and 8 %) is separated out using an amine process, compressed, sent back to the field and re-injected in a deeper formation.

It is expected to store 700 000 tonnes/year of carbon dioxide at a depth of 2 600 m61.

4.5.2 Gas formations

4.5.2.1 In Salah

BP is using EOR technology in Algeria at the Rhourde El Baguel oilfield, which has been in production since the 1960s, but the difference with the gas re-injection projects at I-n-Salah is that, as a gas field, sequestration is motivated not by EOR, for there is no additional oil to recover, but simply to reduce greenhouse gas emissions.

The In Salah gas project had a projected budget of about $3,5 bn which included laying a 520 km pipeline northwards from Krechba to Hassi R’mel, where existing gas pipelines connect to two subsea export pipelines to Europe and a natural gas liquefaction plant on the Algerian coast. I-n-Salah is expected to produce around 9 billion cubic metres of natural gas each year over its anticipated 20-year lifespan.

Like Sleipner, In Salah, is a gas field in which the natural gas has a significant carbon dioxide content, frequently as high as 10 %. Europe, which sources around a third of its natural gas from Algeria, has required that this carbon dioxide content be scrubbed to a maximum of 0,3 % before it is delivered to its markets. In the past this would have been scrubbed and the carbon dioxide vented into the atmosphere. At I-n-Salah the decision was taken to scrub out the carbon dioxide using amines and to build two large compression trains at Krechba to prepare it for re-injection. The re-injection wells run vertically to a depth of more than 2 km, then horizontally for a further kilometre. The $50 m re-injection plant will give a net reduction of carbon dioxide emissions of about 1 million tons a year, or 17 m tons over the lifetime of the project.

Currently, In Salah is the largest operational CCS project in the world (Weyburn being EOR).

4.5.3 Carbon dioxide storage associated with EOR

EOR is a generic term for gaseous injection techniques for increasing the amount of hydrocarbons that can be recovered from an oil field. Using EOR techniques, up to about 60 % of the original oil in the reservoir can be extracted compared with only about 20 – 40 % using primary (oil under its own self-pressure) and secondary (injecting water) recovery. Nitrogen (e.g. at Cantarell in the Mexican Gulf) can be used, and so can methane from natural gas (e.g. Prudhoe Bay, Alaska), and so can carbon dioxide (examples being found in USA, Canada and Hungary).

Oil displacement by carbon dioxide injection relies on the phase behaviour of the mixtures of that gas and the crude, which are, in turn, strongly dependent on the reservoir temperature, pressure and crude oil composition. These mechanisms range from oil swelling and viscosity reduction for the injection of immiscible fluids (at low pressures) to completely miscible displacement in high-pressure applications. In these applications, more than half, and up to two-thirds of the injected carbon dioxide returns with the oil and is usually re-injected into the reservoir to minimise operating costs. The remainder is trapped in the oil reservoir by various means.

Worldwide there are an estimated 100 registered carbon dioxide floods that, in 2006, produced around 250 000 bpd of oil that would otherwise have been unrecoverable. There are currently 74 carbon dioxide - EOR projects operating in the USA (see Figure 18), however, most of these rely on naturally-occurring sources of carbon dioxide. The price of oil does not necessarily justify the processing of carbon dioxide from industrial processes (thus the closure of the Lubbock, Southwest and Mitchell Energy plants, as described in 4.2.1).

Thus over one third of the carbon dioxide injected remains trapped within the geological structure of the oilfield, making EOR an attractive option for storing carbon dioxide. This can be considered a mature technology, as it has been practised for over 45 years.

4.5.3.1 Weyburn

The Weyburn project is by far the largest carbon dioxide EOR project in the world at present. The oilfield was first discovered in 1954, covering an area of around 21 000 ha. It has around 960 active wells and produces about 19 300 barrels of oil/day, or 7 m barrels/year.

In October 2000, EnCana (one of the operators) began injecting significant amounts of carbon dioxide into the Williston Basin (part of the Weyburn oilfield) in order to boost oil production. The initial carbon dioxide injection rate was about 5 000 tonnes/day (2,7 million m3/day). The carbon dioxide would otherwise have been vented to the atmosphere. The gas is from the Dakota Gasification Company Synfuels plant site in North Dakota (see 4.4.1).

It is estimated that 50 % of the carbon dioxide injected will be permanently sequestered in the oil that remains in the ground, the remainder coming to the surface with the produced oil. From here, the carbon dioxide is recovered, compressed and re-injected. Over the life of the project it is anticipated that some 20 Mt of carbon dioxide will be permanently sequestered.

During its life, through miscible or near-miscible displacement with carbon dioxide, the Weyburn project is expected to produce at least 122 million barrels of incremental oil, extending the life of the Weyburn field by approximately 20–25 years. It is estimated that ultimate oil recovery will increase to 34 %62.

4.5.3.2 Abu Dhabi

In January of 2008, the state-owned Abu Dhabi Future Energy Company (ADFEC) joined with Hydrogen Energy (a joint venture between BP Alternative Energy and Rio Tinto) to develop hydrogen-fuelled power in the State63. The facility proposed will process around 100 MMSCFD of natural gas, producing hydrogen and carbon dioxide. The hydrogen will be used to generate 420 MW of low-carbon electricity from a CCGT and the carbon dioxide will be injected into oilfields where the carbon dioxide will be used instead of natural gas to maintain reservoir pressure. This carbon dioxide will be added to about 5 million tonnes/year (57 tonnes/hour) of carbon dioxide collected from a gas-fired power plant, an aluminium smelter and a steel mill64. The total project will collect carbon dioxide from a total of eight different sites, and will store some 15 million tonnes of carbon dioxide per year65.

For Abu Dhabi, the world’s fifth largest oil producer, the benefits of this scheme are obvious. A fully developed network could reduce Abu Dhabi’s annual carbon dioxide emissions by up to 50 % while simultaneously increasing oil production up to 10% and also free up large quantities of natural gas currently re-injected into Abu Dhabi’s oil reservoirs. At the same time 5 % of the state’s power supplies are being met.

The project is expected to come on stream in 2013–2014.

4.5.3.3 Tjeldbergodden

Statoil, in partnership with Shell, has announced its intention to expand its huge methanol plant at Tjeldbergodden to power a new 860 MW gas-fired power station. It is planned that the resulting carbon dioxide should be captured, in this case piped offshore for EOR re-injection into the ageing Draugen and Heidrun oilfields.

4.5.4 Carbon dioxide storage in depleted gas reservoirs

4.5.4.1 Lacq

In June 2009 operation commenced at Total’s integrated pilot demonstration carbon capture and storage facility at Lacq (near Pau) in South West France. This is one of the first fully operational CCS facilities in the world, demonstrating dedicated carbon capture storage from power generation (see Figure 29). This project will trial not only the retrofit of oxyfuel combustion technology to an existing 30 MWth gas fired boiler, but also onshore below ground storage. Carbon dioxide flu gas will be captured and compressed to 30 bar from a 40 tonnes/hour (60 bar, 450 °C) steam boiler, fuelled with gas from the Lacq reservoir. The carbon dioxide will be transported 27 km by pipeline to the nearby depleted Rousse gas field where it will be compressed further to 60 bar for injection 4 500 metres below the Pyrenees. The initial pressure of the Rousse reservoir was 480 bar, and it has now fallen to 30 bar. Approximately 1 50 000 tonnes of carbon dioxide will be captured over a two-year trial period (equating to about 8,5 tonnes/hour), during which time there will be both evaluation of the oxy-combustion capture process and monitoring of the storage location. Reservoir pressure after the two-year trial is expected to be 70 bar.

Figure 29 The Lacq project in South West France

Total is working in partnership with Alstom to convert and operate an existing boiler to the oxy-combustion process, and Air Liquide for the cryogenic separation of oxygen from air where the intention is also to demonstrate a 50 % cost saving versus other capture methods66.

60‘Best practice for the storage of CO2 in saline aquifers. Observations and guidelines from the SACA and CO2STORE projects’, European Commission, IEA Greeenhouse Gas R&D Programme, 2008.

61 Various web pages within the Statoil site http://www.statoil.com/statoilcom/snohvit/.

62’Weyburn enhanced oil recovery project’ IEA Greenhouse Gas.

63‘Carbon technology boosts Abu Dhabi oil United Arab Emirates’: AME Info, May 12 2008.

64‘Masdar awards design contract for Abu Dhabi carbon capture and storage project to Mustang Engineering’, 18 November 2008

65‘BP in talks with Abu Dhabi on carbon-capture project (Update 2)’ Ayesha Daya, Bloomberg.com, 22 January 2009

66 E-mail Cook (Total)/Brown (Progressive Energy), 9 July 2009.