The COP21 provides an opportunity to review the development of carbon capture and storage (CCS). The International Energy Agency expects this technology to contribute to the global effort to reduce CO2 emissions by 15-20%, in line with the Copenhagen target to keep global warming below 2° C by 2100. In its 2014 World Energy Outlook report, the Agency presents a 2° C scenario where, in 2040, global emissions would be reduced from 46 GT, including 21 Gt from the electricity sector (business as usual), to 20 Gt, including 4 Gt from the electricity sector. Combining the use of coal with global climate objectives requires the implementation within the next 25 years of an industry with a size comparable to that of the oil industry. Expectations, hopes and obstacles are briefly presented before we examine the three phases of the complete chain of capture, transport and storage of CO2. Finally, we will offer an outlook regarding the measures that need to be undertaken.
In the 2000s, experts had a very optimistic view on the possibility of reducing anthropogenic CO2 emissions by capturing carbon on large point sources and storing it geologically.
With the technical success of the Norwegian oil company Statoil on the Sleipner site, in the Norwegian North Sea, a rapid development was presented as feasible. The Norwegian government imposes a tax around €30-50/tonne of CO2 emissions in the atmosphere during the operations for the purification of natural gas, necessary if the CO2 content (possibly 30%) is too high with regard to the marketing requirements (2.5%). To avoid paying, Statoil injected, since 1996, almost one million tonnes of CO2 per year into a saline aquifer (the Utsira formation) accessible from the natural gas processing platform.
In the aftermath, British Prime Minister Tony Blair declared at the G8 meeting in Gleneagles in 2005 that Britain fuels the ambition to become the spearhead of the development of this technology in Europe, with four industrial projects. The first project announced was a combined-cycle gas turbine, in Peterhead, Scotland. The UK has both natural resources and industrial edges thanks to its activities in offshore oil and gas extraction. It has end-of-life deposits and available infrastructure, including offshore platforms and oil pipeline systems, as well as large capacity gas pipelines.
Within this context and at the instigation of the Anglo-Dutch oil company Shell, supported by British company BP and Norwegian Statoil, the European Commission, with its directorates-general in charge respectively of R&D, Environment and Energy, created a technological platform for ZEFFPPP (Zero Emission, Fossil Fired Power Plant Platform) quickly renamed ZEP (Zero Emission Platform). The complexity of the subject, with its technological, industrial and societal dimensions, led the Commission to call on representatives of economic sectors potentially involved: power generation, industrial gas sector, oil and gas operators and all of their providers. Non-governmental organizations were also invited to represent the civil society and introduce issues related to societal acceptance into the equation.
Personally, I took great satisfaction in participating in this joint work along with over two hundred experts and officials, some twenty nationalities, from a wide range of industrial sectors, each with their specific culture and issues. Although none of the participants initially knew more than a dozen of the other people, we immediately adopted a collective work mode and implemented self-directed groups and sub-groups; in a few months, they produced a series of high-quality documents, including a strategic research plan and a strategic development plan for technology in Europe. In addition, for each of the basic technological building blocks necessary for the implementation of each technology option, a synthesis of the contributions of all the subgroups of experts also evaluated the technological maturity and the efforts to be made in order to raise the level of industrial achievement.
Issues in the realization of complete chains of capture-transport-storage of CO2 were, for the most part, very quickly identified and classified according to six different categories (Giger, F., Di Zanno, P. et al. : “Making Carbon Capture and Storage Happen in Europe: Markets, Policy, Regulation”, WG4 Subgroup on “Markets, Policy and Regulation”, EU Technology Platform Zero Emission Fossil Fired Power Plants, Brussels, 26 Sept. 2006).
Legal: the status of CO2
A generally accepted principle in environmental protection regulations, at least in Europe, prohibits any injection of liquid waste into the ground. But geological storage of CO2 involves a dense phase or “supercritical” fluid state in which physicists no longer distinguish between liquid and gas phases. A special status for CO2 needs to be defined in order to exclude it from the category of liquid waste.
Again, this potential status of waste requires adaptations, both for crossing land borders and for transport by pipeline under the sea (governed by the London Convention) or to authorize migration in geological structures overlapping maritime borders.
Many technical issues are spontaneously mentioned by engineers, whether for the capture and compression of CO2, its transportation and injection into deep geological structures; these will subsequently be discussed in detail below.
The issue of societal acceptance has been identified at a very early stage, given the issues raised by the long-term deposit of other types of waste and dramatic events such as the lethal outgassing of CO2 in the volcanic crater lake of Nyos in Africa. Thus, non-governmental organizations were invited to participate to the work of the ZEP platform, as of its inception, in order to represent civil society, take into account the perception by the public opinion and prepare an appropriate communication to inform the public.
Like other measures for environmental protection, the implementation of CCS is expected to incur additional costs. Once the feasibility of the concept is demonstrated, these costs need to be assessed, before being reduced through process optimization. Eventually, the mechanisms used to cover the charge will need to be set up.
The operational management of a full CCS chain requires implementing of a wide range of skills and expertise that are seldom available or managed within a single operating company, if only regarding project management. A wide variety of trades are required. Some, such as power generation, are accustomed to low margins – like sedentary farmers; while others, more familiar to the management of geological risk, require quicker and higher returns to compensate for uncertainties – like nomadic hunter-gatherers.
As a result, the clash of cultures between real actors generates a trail of mutual misunderstandings leading to clashes, all the more difficult to overcome as their roots are unexpected, or even, unidentified.
The first quarters of the ZEP platform – whose purpose is to reduce the emissions of anthropogenic CO2 in the atmosphere by developing geological storage – are the perfect illustration: the clash almost destroyed the whole impetus. On one hand, producers of coal-based electricity stress the importance of increasing the efficiency of power plants in order to reduce fuel consumption and, therefore, the amounts of CO2 with respect to the energy produced. On the other hand, oil companies – who promote “the wonderful opportunity for developing their activity thanks to CSC” – opposed the idea of reducing at source the quantity of CO2 that needs storing. On the brink of collapse, when all could have been lost, a modus vivendi was eventually established, which allowed for a more serene team work.
Ten years later, while the use of coal is suffering from a very bad press, particularly in Europe, the perception of CCS concept is very different between electric generators and petro-gas producers. The former see it as a major constraint that could double their production costs, or even make it impossible if a number of barriers are not deleted. Among the latter, while a few remain very optimistic about this prospect, some of them estimate there are significant uncertainties about the geologic storage capacity actually available in half a century, particularly in regions of the world with significant emissions. Many question the relevance of the business model of carbon storage service providers.
In this context, the publicity one of the largest operators in northern Europe promotes for the gas it extracts, by referring to the production of climate-friendly electricity halving CO2 emissions, serves its interests, while promoting a partially correct message. Nevertheless displaying it in Düsseldorf Airport, in the heart of the historic coalfields of the Ruhr, is certainly not helping the interaction between players.
In 2014, the use of coal for electricity generation covers 43% of world needs; it forms the largest share of motionless anthropogenic CO2 sources. The situation in France is completely different because of the preponderance of historical fleets of hydro and nuclear power. However, CO2 isn’t easiest to capture out of power plant boilers, because the content in the flue gas barely reaches 15%. Streams with higher concentrations of CO2 are emitted in the production processes of ammonia, fertilizers (Catalytic Methane Reforming or CMR) and hydrogen. The energy costs of separating from the other gases and purification are much lower. The extraction of CO2 from the so-called acid natural gas, otherwise unfit for consumption, has been carried out industrially for decades. It is performed as long as the value of the gas covers the cost. The transposition of these separation technologies to coal combustion fumes must overcome several pitfalls.
The first is the size of the equipment required to process gas streams that needs to be expanded by one or more orders of magnitude. This would lead to doubling the investments within a time horizon of fifteen years provided that during this period, the cost of additional facilities is reduced by a factor of three to four in order to reduce it to the level of a coal plant without carbon capture technology.
The next problem is the presence of residual impurities in coal fumes. Depollution means, required by the legislation on large combustion plants (dust, sulfur and nitrogen oxides etc.) extract one part but further treatment is required to remove residual acidity (polishing).
Third factor, energy loss for the separation, purification and compression of CO2 in dense phase at over 80 bar prior to transport. In fifteen years, for a modern coal plant with a yield around 45%, energetic expense for the best processes was estimated as a yield reduction of 8 points instead of 12. A research pilot for CO2 capture built in Le Havre established a landmark (F. Giger, F. Chopin, JF Lehougre, « CCS Pilot Project Le Havre: a stepping stone in EDF Group tackle of the CO2 challenge », VGB PowerTech, Essen, 3/2015.). However, this would reduce the overall yield of the equipped plant down to 37%. The theoretical minimum energy loss, according to the theory of thermodynamics, is around 5 performance points. Therefore, for the same production of electricity, an additional amount of 10 to 20% of coal is necessary for the capture and compression, prior to transport.
Last but not least: the increasing complexity of the production process, as many of the capture processes involve industrial chemistry, a less common know-how among thermal power plants operators, less well understood by their management structures (risk of handling reagents, waste disposal, potential loss of flexibility...).
This segment doesn’t pose any unsurpassable technical problem because it is already practiced on an industrial scale by both small sea coasters and by pipelines of hundreds of miles in North America.
The mapping of the transport system will depend on the distance between the power plants and the storage sites i.e. their relative location, something we can’t assess at this time.
The problems that need to be solved will probably imply other kinds of obstacles.
The first is the societal acceptance for crossing geographical areas with a high population density and where the kilometer of pipeline crosses on average thirty properties: each stakeholder will have an opinion on the full CCS chain and, in particular, on the merits of the geological storage of CO2.
Second obstacle, the investment in the transport network. In Europe, the construction of a gas pipeline network, comparable in size, required decades. The time required will be impacted by the duration of the authorization, and possibly expropriation, procedures. Infrastructure costs depend on the geographic location (plain, mountain and sea), in proportion to the growing distance, but benefiting from scale effects with the transported flows.
The inherent difficulties in this field, at least in Europe, have been largely underestimated fifteen years ago and there is still no consensus among experts on this matter.
The reference presented in 2006 by Statoil of injecting one million tons of CO2 per year over 10 years in Sleipner in the Norwegian North Sea spawned the view that it was possible to find aquifers filled with salt water, unsuitable to the usual consumption, over a wide area (several tens of miles) and with a high porosity, greater than 20%. On this basis, the realization of the storage-transport segment should not present any particular difficulty. Its cost shouldn’t exceed 15 to 20% of the total cost of CCS and most of the attention and efforts have focused on capture within the geographical area of the power plants. Other achievements such as in In Salah, in Sahara desert, the upcoming availability of end-of-life oil and gas fields in the North Sea and many enhanced oil recovery (EOR) operations carried out since the 1970s, in North America in particular, supported, for some time, this optimistic view.
Many geological studies cover a mosaic of regions in Europe. By the time we started to compile all the relevant assessments however, we realized they have been carried out according to very different, sometimes even incompatible approaches, making regional syntheses virtually impossible. Assumptions such as the average porosity of the aquifers were based on dispersed values. Worse, in-situ measurements at the bottom of the exploration wells are to few to build on certainties. The explanation is that geological depths sought for storage exceed 1000m to maintain CO2 in dense phase. Only the wells drilled for oil and gas operators reach this depth. The latter focus on hydrocarbon levels. Detailed measurements of injectivity (the ability to inject fluids from the well into the surrounding rock) are very rare, especially in purely aquifer levels, those that are potentially fit for CO2 storage. As for aquifers that have been reached for the purposes of using underlying levels and they are now drilled with multiple wells. These were originally cemented to resist contact with water but, apart from a few exceptions, they were never intended to withstand the subsequent acidifying action of CO2.
The teaching of the France-Nord project, an area including the Paris Basin and covering a priori the most favorable half surface of the metropolis, provided an understanding of complementary elements. It was implemented by a consortium including the main French industrial groups and organizations of geoscience with the support of ADEME. The aim was to carry out an injection pilot project with a reasonable expectation of being able to inject 200 million tons of CO2 over 40 years. This amount corresponds to the emission of a coal fired unit to the current standard (1000 MW run at base load). Earlier work raised hopes for a potential of 30 Gigatons. The results were widely published and showed that several sites would be required to approach the target in terms of pore volume but that the permeability was not at scale with the intended injection rate for 40 years. Beyond the static volume evaluation, the dynamic factor of injectivity proves prohibitive. This parameter is never mentioned in the vast majority of global publications on the subject. Hence the question: “Have we overestimated saline aquifer CO2 storage capacities? ” (S. Thibeau & V. Mucha, IFP Energies nouvelles, vol. 66 (2011) 1 pp. 81-92).
The reduction in investment and operating costs of the capture must be the result of both the experience gained on industrial size projects and more fundamental research leading to technological breakthroughs.
The retrofit project of Boundary Dam 3 in Canada (Saskatchewan), with an initial power of 139 MW, was launched in February 2008. The agreed investment of a total 1.5 billion Canadian dollars has been widely supported by subsidies. It enabled to increase the gross power of the unit up to 160MW and commission, in October 2014, amine-based post-combustion capture unit. The cost of the latter would reach US$6000/MW. The output power of the tranche was reduced to 110-120 MW due to the energy penalty of 40-50 MW. The cost per tonnes of CO2, the emission of which was avoided from the power plant, would reach 100 CAD. The sales value of the captured CO2 for enhanced recovery needs of the Weyburn oil field was never officially communicated but could be around 25 dollars per tonne.
The project of the 582 MW lignite power plant in Kemper County (Mississippi), in the United States was launched in 2010 and implements gasification. Its commissioning is scheduled for 2016 for a total budget of 6.2 billion US dollars, with an additional cost of 9500 dollars/MW for capture.
Technically, the reduction of the energy penalty is subject of significant efforts to save fuel in order to reduce costs and promote sustainable development. However, in the absence of an international standard for benchmarking purposes, the assessment method for measuring energy penalty varies according to the authors. Its development is underway at the ISO (International Standard Organization).
As chemical processes generally require stable operation, efforts are required to improve the flexibility of carbon capture installations in order to avoid penalizing the power production units. Connecting trains in parallel to cover, for example, half or a third of the total flow of the combustion fumes is a possible development path. It seems particularly promising for the oxycombustion technology. Combustion with oxygen avoids having to separate nitrogen from the air in the fumes and even brings an interesting potential flexibility if oxygen is produced and stored during off-hours for use during peak demand.
Practiced on a large scale in North America, transporting CO2 can be considered as a mature technology.
Because of the diversity of opinions among experts, it is necessary to establish a methodology by unanimity to assess regional potential storage. An improved understanding of the dynamic mechanisms in aquifers during the injection phase (and subsequent phases) is required, if only to know how many orders of magnitude the pore volume needs to be cut down in order to provide a CO2 storage volume available in a few decades. Concepts such as the extraction of water from aquifers deposits in order to create room for the storage of CO2 need to be assessed. Moreover, each geological site is a specific case that needs to be understood as such.
Appraisal drillings, paired with injectivity tests, and the construction of injection pilot plants will be required to assess most major deep aquifers with salt water because they have been very little explored, as there was no significant economic interest so far. If reasonable expectations can be expressed for North America, the results on the ground in Europe are rather disappointing and the situation of China and India requires extensive studies and exploration.
Two other non-technical issues need to be tackled in order to allow the geological storage of CO2: public acceptance, particularly for onshore storage, which has clearly not increased in ten years; and the establishment of a storage business model of CO2. Before getting involved in such an activity, an operator in geoscience will need to cover both the geological, market and operational risks to feed the hope of adequate remuneration.
CCS technology is the only way to combine a massive use of coal and the fulfilment of the objectives to reduce greenhouse gas emissions. The conditions for success include the reduction of capture costs by a factor 5 and a precise identification of geological storage resources. In countries still depending on coal consumption, particularly China and India, injectivity tests should be performed at the bottom of appraisal drillings in order to prove the possibility to access storage sites at the required pace.
The industrial effort needed over a period of twenty years is considerable. For capture, the cumulative size of the set of facilities to be implemented is comparable to that of the global refining industry. For transport, it is comparable to the network of natural gas pipelines. And for storage, it is comparable to the whole operating infrastructure of the largest deposits of oil and gas.
Will public authorities prove able to implement global mechanisms in order to finance these efforts? What of public acceptance? These questions remain open.