4.1 Current activities
4.1.1 Natural gas processing
Capturing and storing CO2 from high-CO2 content natural gas field presents some of the least cost ‘earliest opportunities’ for large-scale deployment of integrated CCS projects across a number of world regions. Gas processing facilities typically have access to in situ or close proximity storage sites of known geological characteristics and there is a considerable skills and knowledge base within the oil and gas industry required to undertake large commercial-scale projects. There are currently five fully integrated, commercial-scale CCS projects in operation worldwide, of which four are associated with the separation of CO2 from natural gas and one from coal-based SNG production (Box 1).
The Sleipner and Snøhvit (Norway) and In Salah (Algeria) projects involve the stripping of CO2 from high-CO2 content natural gas to achieve sales-grade quality natural gas. The CO2 is stripped, collected and stored securely in underground geological formations. The Rangely project (United States) also uses CO2 captured from natural gas processing at the ExxonMobil LaBarge gas plant in Wyoming, but uses the CO2 for enhanced oil recovery (EOR) and storage at the Rangely field in Colorado.
ChevronTexaco is currently in the final planning phases for one of the largest CCS projects in the world involving capturing CO2 from the Gorgon natural gas field located 130km off the north-west coast of Western Australia. The project comprises the establishment of a gas processing and LNG facility on Barrow Island, which lies directly between the gas fields and the Australian mainland. The Gorgon natural gas reservoirs contain naturally occurring CO2 levels of approximately 14%, which requires removal before the gas can be liquefied. The removal is necessary as CO2 would freeze in the LNG process, potentially damaging the equipment. Current standard practice by all operating LNG facilities worldwide is to vent this CO2 to the atmosphere. Chevron have proposed that over 3.4 million tonnes of CO2 per year will be injected into the Dupuy saline reservoir beneath the north end of Barrow Island. A re-injection facility to store CO2 beneath Barrow Island would be sized to accommodate the full stream of separated reservoir CO2. Re-injection would commence as soon as practicable after the gas processing facilities commissioning and start-up process. All studies undertaken to date by the Gorgon joint venture indicate that re-injection is technically feasible and the joint venture is committed to re-inject reservoir CO2 unless it is proven to be technically infeasible or cost-prohibitive. Final approval for the development was granted in August 2009, and it is predicted that customers in Western Australia will begin to be supplied from 2015 (IEA GHG, 2006).
Box 1. Summary of existing CCS projects worldwide
Five fully-integrated, large scale CCS projects are in commercial operation today. Four projects – Sleipner, In Salah, Snøhvit and Rangeley – inject CO2 from a natural gas production facility where it is separated from the natural gas and sent to market. In the first three cases, the CO2 is injected into saline aquifers, while in the fourth it is used for enhance oil recovery (EOR). A fifth project captures CO2 at the Great Plains Synfuels plant and transports it for EOR to the Weyburn-Midale Project. All five are contributing to the knowledge base needed for widespread CCS use.
Sleipner. The Sleipner project began in 1996 when Norway’s Statoil began injecting more than 1 million tonnes a year of CO2 under the North Sea. This CO2 was extracted with natural gas from the offshore Sleipner gas field. In order to avoid a government-imposed carbon tax equivalent to about USD 55/tonne, Statoil built a special offshore platform to separate CO2 from other gases. The CO2 is re-injected about 1km below the sea floor into the Utsira saline formation located near the natural gas field. The formation is estimated to have a capacity of about 600 billion tonnes of CO2, and is expected to continue receiving CO2 long after natural gas extraction at Sleipner has ended.
In Salah. In August 2004, Sonatrach, the Algerian national oil and gas company, with partners BP and Statoil, began injecting about 1 million tonnes per year of CO2 into the Krechba geologic formation near their natural gas extraction site in the Sahara Desert. The Krechba formation lies 1, 800 metres below ground and is expected to receive 17 million tonnes of CO2 over the life of the project.
Snøhvit. Europe’s first liquefied natural gas (LNG) plant also captures CO2 for injection and storage. Statoil extracts natural gas and CO2 from the offshore Snøhvit gas field in the Barents Sea. It pipes the mixture 160 kilometres to shore for processing at its LNG plant near Hammerfest, Europe’s northernmost town. Separating the CO2 is necessary to produce LNG and the Snøhvit project captures about 700,000 tonnes a year of CO2. Starting in 2008, the captured CO2 is piped back to the offshore platform and injected in the Tubåsen sandstone formation 2,600 metres under the seabed and below the geologic formation from which natural gas is produced.
Rangely. The Rangely CO2 Project has been using CO2 for enhanced oil recovery since 1986. The Rangely Weber Sand Unit is the largest oilfield in the Rocky Mountain region and was discovered in 1933. Gas is separated and re-injected with CO2 from the LaBarge field in Wyoming. Since 1986, approximately 23–25 million tonnes of CO2 have been stored in the reservoir. Computer modelling suggests nearly all of it is dissolved in the formation water as aqueous CO2 and bicarbonate.
Weyburn-Midale. About 2.8 million tonnes per year of CO2 are captured at the Great Plains Synfuels Plant in the US State of North Dakota, a coal gasification plant that produces synthetic natural gas and various chemicals. The CO2 is transported by pipeline 320 kilometres (200 miles) across the international border into Saskatchewan, Canada and injected into depleting oil fields where it is used for EOR. Although it is a commercial project, researchers from around the world have been monitoring the injected CO2. The IEA Greenhouse Gas R&D Programme’s Weyburn-Midale CO2 Monitoring and Storage Project was the first project to scientifically study and monitor the underground behaviour of CO2. Canada’s Petroleum Technologies Research Centre manages the monitoring effort. This effort is now in the second and final phase (2007–2011), of building the necessary framework to encourage global implementation of CO2 geological storage. The project will produce a best-practices manual for carbon injection and storage.
Source: (IEA/CSLF, 2010)
In addition to the projects described previously, there are several proposed projects at different stages of development involving the capture and storage of CO2 from natural gas facilities. Other proposed CCS projects at less advanced stages of development include (IEA/CSLF, 2010):
Browse LNG Development (Western Australia). The proposed CCS project would process gas from three natural gas fields over 400 km offshore from Broome in Western Australia. The Browse Joint Venture comprises Woodside Energy, BHP Billiton, BP, Chevron and Shell. Front End Engineering and Design (FEED) studies are expected to be undertaken in 2011 to enable a Final Investment Decision by mid-2012. The project is expected to capture up to 3 MtCO2 per year and commence operation in 2017.
Fort Nelson CCS Project (British Columbia, Canada). The project proposes to capture CO2 from Spectra’s Fort Nelson natural gas processing plant and store it in the deep saline formations of the Western Canadian Sedimentary Basin. The Fort Nelson CCS Project is a partnership initiative of Spectra Energy Transmission, the Energy & Environmental Research Center Plains CO2 Reduction Partnership, the Province of British Columbia, and the Government of Canada. The project is expected to initially capture 1.2 MtCO2 from a demonstration plant in operation from 2010 to 2017 followed by an increased annual capture of 2.2 MtCO2.
Occidental CCS Plant (Texas, United States). In June 2008 Occidental Petroleum and SandRidge Energy announced plans to build a $1.1 billion natural gas processing and carbon capture plant in west Texas. The CO2 is planned to be used in an EOR project. The gas processing plant combined with the existing SandRidge gas processing plants could provide over 8 MtCO2 per year for capture. A new 160-mile long pipeline will be constructed from the plant, through McCamey, Texas, to the industry CO2 hub in Denver City, Texas.
4.1.2 Industrial hydrogen production and use
Ammonia & fertiliser production
CO2 is routinely captured from ammonia plants for use in the production of urea and nitro-phosphates, often within the same integrated plant. Where demand for the CO2 stream does not exist - either from urea or other nearby industrial production activities - the emissions are routinely vented to atmosphere. The Enid Fertilizer plant in Oklahoma, United States, operated by the Koch Nitrogen Company has captured over 600,000 tCO2 per year since 2003 for use in EOR and a CCS project is being proposed at the Coffeyville Resources petroleum coke gasification-based ammonia and urea ammonium nitrate production facility in Kansas. The project will also capture around 600,000 tCO2 per year for use in domestic EOR and/or geological storage (Blue Source media release, 21 August 2007).
In addition, the Indian fertilizer industry has begun capturing CO2 from flue gases to meet CO2 demand at natural gas-based ammonia-urea production plants. This is because the use of natural gas as feedstock does not provide sufficient amounts of CO2 as required for urea production. Consequently, the use of a Carbon Dioxide Recovery Plant (CDR) for the capture of CO2 from flue gases emitted from existing fossil fuel combustion sources has been employed. Several of these projects have been recognised as eligible United Nations Clean Development Mechanism project activities, based on Approved Methodology AM0050. This methodology was developed on the basis of a proposed CDR project by the Indian Farmers Fertilizer Cooperative Ltd. The use of CDR to supplement the CO2 balance for urea production represents an alternative to supplementing natural gas with naphtha feedstock, which has higher carbon content and thus results in greater process CO2 emissions per unit of ammonia production.
Notwithstanding the use of ammonia derived EOR at two sites in the United States and the emergence of CDR in the Indian fertiliser industry, there are presently no other proposals for CCS projects in the ammonia production industry.
Coal-to-liquids production
Although no CCS projects are currently operational, several major plans to integrate CCS with CTL production plants are under development in Australia and China. The Monash Energy CTL Project in Victoria, Australia is a proposed project that will involve the drying and gasification of brown coal for conversion to synthetic diesel, followed by the separation of the produced CO2 (up to 13 Mt per year), with transport and injection into a suitable storage site. This project was originally planned to commence in 2015 and was estimated to cost USD 6 billion to USD 7 billion. Partners involved in this project include Monash Energy, Anglo American and Shell (IEA, 2008; CO2CRC, 2009). However, the project has currently been postponed.
The FuturGas Project in South Australia is a joint venture between Hybrid Energy Australia and Strike Oil to research and develop the CO2 storage component of another project which involves the gasification of lignite for the production of synfuels. It is proposed that the CO2 (captured post-gasification) will be stored in the Otway Basin to the south of the lignite resources. The project is expected to begin by 2016 (Hybrid Energy, 2010).
China National Petroleum Corporation has begun construction of the nation’s first potential integrated CCS project, involving capture from the Shenhua Group’s coal-to-liquid project in Ordos, Inner Mongolia. The facility will initially be able to capture and store 100,000 tCO2 per year, with annual capacity to be subsequently increased to 1–3 MtCO2 in two phases (China CSR, 2010). In addition, in May 2007 Dow and Shenhua announced plans for coal-to-chemicals complex at the Yulin chemical plant in Shaanxi Province, China. The project aims to convert coal to methanol to produce ethylene and propylene, and could capture 5–10 MtCO2 per year by 2015 (IEA/CSLF, 2010).
Although not a CTL project, the Weyburn-Midale project in North America involves the capture of CO2 from the Great Plains Synfuels coal-based SNG plant in North Dakota. The captured CO2 is compressed and sent via pipeline to the Weyburn and Midale oil fields in Canada, where it is also used for EOR as well as storage. Currently, over 5 Mt CO2/year is stored from these plants (Box 1; IEA, 2009b).
4.1.3 Ethylene oxide production
There are no known plans to undertake capture and storage from ethylene oxide production at present. As CO2 emissions from most existing plants are typically small (around 150–250 ktCO2 per year) it is likely that economies of scale would preclude cost-effective capture unless emissions could be captured as part of an integrated multi-source CCS network. Early opportunities may exist for integrated chemical complexes and larger facilities combined with ethylene and/or ethylene glycol production.
