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One of the critical problems of our industrialized civilization and social-economic systems is the destabilization of the biosphere by artificial emissions, which can no more be controlled and absorbed by natural processes. Increasing emission of carbon dioxide (CO2) has a major impact on global warming. Significantly large quantities are created as exhaust gases from global industrial production – such as cement and steel industries, but mainly from fossil fuel-driven electric power plants – but also as associated gas from oil and gas production. CO2 has not only a negative impact on the environment as the so-called “Greenhouse Gas” – CO2 at higher concentrations is directly “lethal” for the human body.
In the light of current knowledge and technical developments, the only way to reduce those emissions is to separate CO2 and store it underground. There is no other solution – and this solution is technically possible. The industry aims to extract CO2 from exhaust gases and capture it in large quantities in artificial storage in subsurface geological formations . Such underground storages are already geologically very well known and sometimes applied as storages for natural gas in subsurface underground formations, e.g., saline aquifers.
According to the International Energy Agency , carbon capture and storage (CCS) is a central measure to substantially reduce CO2 emissions and meet the target (∼26 GtCO2/year by 2030) sought by the international community. CCS involves the capture of carbon dioxide from point sources of emissions and its injection into geological bodies, where it would be permanently retained.
While the broad deployment of CCS has significant potential for carbon mitigation, there is growing interest in using the trapped CO2 in a way that can create economic value , often referred to as carbon capture and utilization (CCU). The most extensive use of CO2 today is enhanced oil recovery, which creates economic incentives for the permanent storage of a large volume of CO2 in geological formations. Apart from EOR, in recent years, CCU has progressively become focused on converting CO2 into carbon-based economically viable fuels and feedstocks, not only for economic reasons but also because these products could reduce the use of their fossil fuel-based equivalents, act as a dense energy carrier for renewable electricity, and be necessary for a net-zero emissions future.
1.2 Carbon Capture & Storage
CO2 capture technologies are currently available for removing CO2 from industrial processes and flue gases of power plants. The three main CO2 capture systems associated with different combustion processes are pre-combustion, post-combustion and oxyfuel combustion. In addition to them, CO2 capture during natural gas production can also be considered . Indeed, in the gas conditioning process, CO2 is typically removed from raw natural gas in the Acid Gas Removal Unit (AGRU) in order to meet downstream sales specifications. Many CO2 separation technologies can be successfully applied for both purposes, namely for CO2 capture from emission sources and for CO2 removal from natural gas. This is the case, for example, when considering the conventional chemical absorption process that makes use of aqueous solutions of amines to capture CO2 from flue gases as well as to remove CO2 from natural gas (preferably, if the CO2 content is not higher than 15 mol%).
More recently, some studies have been carried out to identify and understand the similarities and contrasts between the CCS industry and the Liquefied Natural Gas (LNG) export industry. The global LNG trade is expected to grow in a significant way soon, giving a major contribution to the expansion, integration and flexibility of the global natural gas market. LNG production requires a deep removal of carbon dioxide, down to levels of ppm, to meet LNG downstream process specifications allowing to avoid CO2 freezing.
2 TOP FACILITIES WORLDWIDE
2.1 Century Plant
Controlled by Occidental Petroleum (Oxy), the Century natural gas processing facility in West Texas, U.S., is the world’s single biggest CCS plant . Oxy and Sandridge Energy entered an agreement to build and operate the Century CCS facility back in 2008. Built with an investment of approximately $1.1 billion, the plant captures carbon dioxide that is used for the company’s enhanced oil recovery (EOR) projects in the Permian Basin. The CO2 capturing plant began operations in 2010 by commissioning its first train, which has a design capacity of 5 Mtpa of trapped CO2. The second line was commissioned in late-2012 to add an additional capacity of 3.4 Mtpa. The gas captured by the facility is delivered to an industrial hub located in Denver City (Texas) through a 160 km pipeline.
2.2 Carbon Dioxide Flooding and Storage in China
The oilfields which have been developed gradually entered the stage of high water cut and recovery degree in China. The newly discovered oilfields are mainly composed of ultra-low permeability reservoirs and tight reservoirs, which are difficult to be recovered. As a consequence, China faces the severe challenge of increasing or even maintaining oil production; there is an urgent need for a new method to enhance the oil recovery of old oilfields and producing rate of new reservoirs.
In China, as early as the mid-1960s, some laboratory experiments regarding carbon dioxide flooding were carried out in Shengli Oilfield and Daqing Oilfield. Furthermore, in the mid-1990s, some pilot tests were conducted in Daqing Oilfield, Jiangsu Oilfield, Zhongyuan Oilfield, and Shengli Oilfield. During the period of “the eleventh five-year plan”, PetroChina discovered a natural gas reservoir that contains a large amount of carbon dioxide in the Songliao Basin.
After years of research, scholars and engineers have deepened two fundamental theories, which are suitable for the Chinese continental sedimentary reservoir of CO2 miscible flooding theory and the storage mechanism of CO2 storage in the reservoir and saline layer. They also formed and developed six key technologies: the reservoir engineering technology of CO2 flooding and storage, CO2 flooding technology with high efficiency of injection and production, CO2 long-distance pipeline and supercritical injection technology, treatment and cyclic gas injection technology of the produced fluid by CO2 flooding, monitoring and dynamic analysis and evaluation technology of CO2, and CO2 flooding and storage potential evaluation and strategic planning. Relevant research results supported the Black 59, Black 79, Black 46, and Yi 59 Blocks in Jilin Oilfield to build five kinds of demonstration areas of CO2 storage and flooding, covering the geological reserves of 12 million 880 thousand tons, 69 gas injection wells groups.
The cumulative gas injection was 970 thousand tons, which has increased 102 thousand tons of oil. The annual oil production capacity reached 121 thousand tons. So it showed significant economic benefits. The CO2 yearly storage capacity was 350 thousand tons, indicating a crucial social significance of greenhouse gas emissions. At present, the technology has been extended to the oilfields in Western China, and Ordos Basin and Junggar Basin pilot tests are being carried out. The prospect of carbon dioxide flooding and storage technology in China is broad.
2.3 Tomakomai CCS Demonstration Project
Tomakomai is Japan’s first full-chain CCS project, which captured and stored CO2 from a coastal oil refinery on Hokkaido Island in Japan. The refinery’s hydrogen production unit produced off-gas containing about half carbon dioxide, which was captured in an active amine process. The venture caught around 0.1 Mt CO2 during each year of operation (2016-2019) for injection into two nearby offshore saline aquifers for storage and monitoring. By the end of the demonstration period, the project achieved its target of 0.3 Mt of CO2 captured and ceased injection as planned. Measurement and monitoring of the stored CO2 will continue during the post-injection stage.
The CCS Demonstration Project is led by Japan CCS Co. Ltd, established in 2008 by major national companies interested in advancing and testing CCUS technology and safety. The objective of this consortium is to implement and demonstrate CCUS projects in the country and investigate associated technologies through international collaboration. The Tomakomai project was commissioned to the Japan CCS Co. Ltd in 2012 by the Ministry of Economy, Trade and Industry, and from 2018 onwards by New Energy and Industrial Technology Development Organization.
2.4 Nordic Seas
Within LNG processing, there are two major CO2 streams where CCS can be implemented: (i) CO2 capture in the gas conditioning process, where the CO2 present in the feed gas is removed, and (ii) CO2 capture from combustion sources (flue gas) from the various gas turbine drivers in the LNG process, particularly the LNG liquefaction process.
Considering the first opportunity, the CO2 captured from the AGRU is already part of CCS, where the CO2 will be sequestrated in a saline aquifer, for example, in two LNG projects: the Snøhvit project and the Gorgon project. The former was constructed to exploit three gas fields (Snøhvit, Albatross, and Askeladd) in the Barents sea: the gas production system uses a subsea production platform, which feeds gas to an LNG processing plant located on Melkøa Island (near Hammerfest, in Norway) via a 143-km pipeline. The CO2 removed from the gas stream is piped 152 km back to the field for injection into an offshore deep saline formation through a dedicated well (it has been reported that around 0.7 MTPA of CO2 have been safely injected and stored since 2008).
The carbon dioxide capture and storage facility lies 2.6 km beneath the seabed of the Snøhvit field and a 153 km pipeline for reinjection . The facility can store 700,000t of carbon dioxide annually. Statoil led the project as part of a consortium of eight companies: Petoro, TotalFinalElf, Gaz de France, Amerada Hess, and RWE-DEA.
The second previously mentioned project (i.e., the Gorgon project) is being constructed on Barrow Island. It will receive its entire feed from subsea wells, as already done in the Snøhvit project, but at a larger scale (the Gorgon project will be a factor 4 times larger than the Snøhvit one in terms of LNG capacity). This project is handling a relatively impure feed stream, with CO2 being one key impurity that has been committed to being sequestered in a saline aquifer below Barrow Island.
2.5 Petra Nova
Commissioned in 2017, the Petra Nova-WA Parish Carbon Capture Project is located in Fort Bend County, approximately 60 km southwest of Houston, Texas. It is designed to capture roughly 90% of the carbon dioxide from a 240 MW slipstream of flue gas from the Petra Nova power plant’s 610 MW coal-fired unit eight and extract approximately 1.6 million tonnes of carbonated gas a year.
The extracted CO2 is used for EOR at the West Ranch Oil Field located on the Gulf Coast. The process involves the discharge of captured carbon dioxide into mature reservoirs in the property asset to release more crude, making the most of the existing oil field while extending its useful life.
The project is owned and operated by Petra Nova CCS I, a joint venture between JX Nippon Oil & Gas Exploration and Petra Nova, where the former is a wholly-owned subsidiary of JX Nippon the latter is a subsidiary of NRG Energy. Built at an estimated cost of $1 billion , the project received $190 m in funding from the US Department of Energy as well as project management guidance from the US Department’s National Energy Technology Laboratory.
2.6 DAC 1
When it launches operations in 2024, DAC 1 is set to become the world’s largest direct air capture (DAC) facility. This landmark facility is an important project that can help demonstrate the valuable and singular role of DAC for meeting net-zero goals. DAC 1 is being financed and built up by 1PointFive, a development company created by Oxy Low Carbon Ventures (OLCV). It will be placed in the Permian Basin of the United States.
The facility will use DAC technology from Carbon Engineering, a Canadian company founded in 2009 with the mission to develop and commercialize a technology that captures CO2 directly out of the atmosphere at a megaton-scale . It features a scalable setup including air contactors that pull in atmospheric air, which, in the presence of a potassium hydroxide solution, reacts to bind and separate the CO2. Through a series of chemical reactions, this process yields a pure, compressed stream of CO2 that will be sent to geologic storage sites to remove this carbon from the atmosphere permanently.
In 2021, OLCV awarded the Front End Engineering and Design phase to a global professional services provider. This phase of DAC 1 is focused on a first capture train with a planned annual capture capacity of 0.5 MtCO2; the project’s total capacity will subsequently increase to 1.0 MtCO2/year. The project is backed by a multi-million dollar investment from United Airlines and, upon approvals, two key policies: the United States’ 45Q tax credit and California’s Low Carbon Fuel Standard .
2.7 Boundary Dam, Saskatchewan
SaskPower’s Integrated Carbon Capture and Storage Facility is the world’s first fully integrated and full-chain CCS facility on a coal-fired power plant — precisely on Unit 3 of the Boundary Dam power station (BD3 ICCS). The captured carbon is used for EOR in a nearby oilfield and injection into a deep saline reservoir at a research project called Aquistore . The complete chain cluster of facilities is close to the BD3 facility, providing a full demonstration and operation of proven and safe CCS.
The CANSOLV process, an amine solvent system, was selected as the capture technology for the BD3 ICCS project. As depicted in Figure 5, this process consists of two distinct processes working in series: the CO2 Capture Train and the sulphur dioxide (SO2) Capture Train. The latter is a Cansolv amine-based desulphurization process that extracts 99% of the SO2 from the flue gas. The fixed SO2 is sent to a Sulphuric Acid Plant, where it is converted into sulphuric acid. The desulphurized flue fluid passes through the CO2 Capture Train, where up to 90% of the dioxide is removed. Steam pulled out from the Intermediate Pressure – Lower Pressure (IP-LP) crossover on the BD3 turbine is needed to regenerate the amine in both flows. The CO2 product is compressed to 2500 psi and is conveyed approximately 70 km by pipeline continuously for utilization in the enhanced oil recovery operation at the Weyburn oilfield. Once there, it is injected 1.7 km below the surface into the oil-bearing Midale geological formation – and – on a sporadic basis, CO2 is transported by a 2 km pipeline to the Aquistore site for recharge and long-term geological storage in the Deadwood deep saline aquifer at a depth of about 3.4 km.
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