Figure 5 The Sleipner oil field platform in the North Sea off the Norwegian coast that includes the world’s first large-scale CCS project (courtesy of Statoil).
Sleipner is the name of an eight-legged horse in Norse mythology. It is also the name of the world’s first commercial CCS project (see figure 5). Located in the North Sea about 240 km off the coast of Norway, Sleipner has been storing about one million tonnes of CO2 per year since October 1996. The source of the CO2 is from the natural gas produced at the platform, where its CO2 concentration is about 9 percent. Before shipping the gas to customers, the CO2 concentration needs to be reduced to under 2.5 percent. As at many gas fields around the world, this is accomplished using amine technology. Unique to Sleipner, however, this is the world’s first installation where the CO2 removal takes place on an offshore platform. The captured CO2 is then compressed and injected underneath the platform into the Utsira Formation, a sandstone layer lying 1 km beneath the North Sea. While there are commercial carbon capture projects that predate Sleipner, their motivation was to produce CO2 for use in commercial markets. Sleipner “marked the first instance of carbon dioxide being stored in a geologic formation because of climate considerations.”1
Figure 5 The Sleipner oil field platform in the North Sea off the Norwegian coast that includes the world’s first large-scale CCS project (courtesy of Statoil).
The majority owner of Sleipner is the Norwegian national oil company Statoil. Its stated motivation to include CCS in its oil and gas production facilities at Sleipner was to avoid a carbon tax for offshore operations in Norway, which was approximately $50/tCO2. The incremental investment for CCS was about $80 million, which yielded a simple payback of only 1.6 years. However, my discussions over the years with Norwegians from both Statoil and the government painted a more nuanced story. The Norwegian government has a strong commitment to climate change mitigation, and it wanted to showcase that commitment to the world. Since the government is the biggest shareholder in Statoil, it used its influence to push the project. While the savings from the carbon tax paid for Sleipner, the motivation to undertake the project went well beyond simple economics.
CCS is a good fit for a country like Norway that is heavily dependent on the oil and gas industry, but also wants to be a leader in addressing climate change. This desire can be traced to Gro Harlem Brundtland, who was prime minister of Norway: “In 1983, Brundtland was invited … to establish and chair the World Commission on Environment and Development, widely referred to as the Brundtland Commission. She developed the broad political concept of sustainable development in the course of extensive public hearings, that were distinguished by their inclusiveness. The commission, which published its report, Our Common Future, in April 1987, provided the momentum for the 1992 Earth Summit.”2 A major outcome of the Earth Summit was the UN Framework Convention on Climate Change, which is the umbrella treaty for all subsequent international agreements on dealing with greenhouse gas emissions.
Sleipner heralded what can be called the third phase of carbon capture, the primary purpose of which is climate change mitigation. The first phase started back in the 1930s, with the invention of the amine process, to remove unwanted CO2 from gas streams. A second phase emerged in the 1970s, when carbon capture became an economic source of CO2 for utilization. This second phase was critical in building up both knowledge and infrastructure to enable phase three. One such contribution was the development of technology to capture CO2 from the flue gases of power plants or other combustion sources.
As discussed in chapter 4, CO2 is expensive to transport in small quantities. This explains why, in areas far from existing sources of commercial CO2 but where a market need exists, capturing CO2 from flue gases became a viable option. Because the concentration of CO2 in flue gases is dilute, the production cost was higher than most of the traditional sources used to produce it for commercial markets. However, for projects needing a significant amount of CO2 not located near a commercial source, it became economic because of the savings in transport costs. As discussed in chapter 3, the first of these facilities was at Searles Valley Minerals, which is still in operation today.
In the early 1980s, three carbon capture plants, ranging in size from 100 to 1,200 tCO2/day, were built in Texas and New Mexico to produce CO2 for enhanced oil recovery (EOR). The Arab Oil Embargo of 1973 and subsequent oil shocks had sent oil prices soaring and amplified the pressure to increase the production of domestic oil. The high oil price made capturing CO2 from flue gases economical for EOR applications. The economics shifted again in 1986 when the oil price collapsed, forcing all three plants to close.
In the late 1980s and early 1990s, about a dozen more plants capturing CO2 from flue gas were built around the world, including the United States, Australia, Japan, Brazil, China, and India. These plants are relatively small, generally 100–300 tCO2/day, and produce CO2 primarily for the food and beverage market or for urea production.3
As discussed in chapter 4, the use of CO2 for EOR started in 1972, with natural reservoirs providing most of the CO2. Over the years, carbon capture augmented this supply, as shown in table 4. Most of the activity was in the United States, but in recent years projects have spread to other countries, specifically Brazil, Saudi Arabia, and China.
Source: GCCSI, The Global Status of CCS, Vol. 2: Projects, Policy and Markets (Melbourne: Global CCS Institute, 2015), 56–59.
There are some common aspects to the ten projects listed in table 4. The CO2 comes from one of three sources: natural gas processing, fertilizer production, or coal gasification. Because a carbon capture step is necessary in these industrial processes, they bear the cost of capture. In all of them, carbon capture is relatively inexpensive, because the CO2 is captured from a high-pressure stream. The incremental cost to make the CO2 available for EOR is simply due to the expenses of compression and transport. In most of these projects, the price paid for the CO2 by the EOR operators covers these incremental costs.
The motivation for most of these projects is the desire to use CO2 for EOR. The auxiliary benefits for CCS, such as building pipeline infrastructure and storing CO2, were generally not the driving force. The one big exception is the Weyburn project that came on-line in 2000.
The Great Plains Synfuels Plant near Beulah, North Dakota, is the only surviving project from the synfuel programs of the 1970s. Those programs were instituted in response to the spike in oil prices caused by the Arab Oil Embargo. The purpose was to use the vast coal resources of the United States by converting the coal to oil and gas; the Beulah plant, specifically, converted coal to a substitute natural gas. A by-product was a high-purity stream of CO2, which was simply vented to the atmosphere for many years. The Weyburn project, which stores approximately 3 million tonnes of CO2 each year, involved building a 330 km pipeline from Beulah to the Weyburn and Midale oil fields in Saskatchewan, Canada. Unlike most EOR projects, which only want to maximize oil production, Weyburn also took into consideration how to maximize CO2 storage; in addition, it undertook an extensive scientific program studying the measurement, monitoring, and verification of CO2 in the subsurface.4 Of all the large-scale carbon capture EOR projects, Weyburn has made the most significant contributions to the furthering of CCS technology.
Starting with Sleipner, over a dozen large-scale carbon capture projects whose primary motivation is climate change mitigation have come on-line. I have classified these projects into three categories: pioneer projects, industrial projects, and power projects. This section contains examples of each category.
The pioneer projects share two traits: they were built with little or no government support, and the CO2 is a by-product from natural gas processing. Since this is a high-purity source of CO2, CCS costs are limited to compression, transport, and storage. This CCS cost was a small part of a larger project, roughly 10 percent, and the larger project could afford to absorb those costs and still be profitable. The companies could justify the added costs as an expense of doing business and/or because the project aligned well with a broader business strategy. Sleipner was the first of four pioneer projects.
The second pioneer project to come on-line was BP’s In Salah Gas Project, in 2004.5 Located in the Algerian desert, it removes CO2 from the produced natural gas and injects it 1.9 km down into the Krechba Formation, a depleted gas reservoir. The estimated incremental cost for the CO2 storage is $6/tCO2. The operation was suspended in 2011 after 3.8 million metric tons were injected. There was a concern about the seal integrity due to pressure rise in the reservoir, a result of the relatively low permeability of the Krechba Formation. At the time it was built, the project fit in very well with BP’s overall strategy; wanting to be seen as a green company, BP launched a marketing campaign with the theme “Beyond Petroleum.” The company initiated several other major CCS projects around that time, but In Salah was the only one that ever became operational.
As a sequel to Sleipner, Statoil led another pioneer project, Snohvit, which came on-line in 2008.6 Located in the Barents Sea off the coast of far northern Norway, it captures about 700,000 metric tons of CO2 per year and injects it into a sandstone formation 2.6 km below the seabed. While the motivation for the Snohvit project was similar to Sleipner’s, the projects look very different. Sleipner first processes the produced natural gas on a platform before sending the gas to shore in a pipeline and injecting the captured CO2 below the platform. At Snohvit, there is no platform. Instead, the entire operation is located on the seabed and is fully automated. It pipes the produced gas containing 5–8 percent CO2 approximately 150 km to an island near the Norwegian coast, where the CO2 is removed and the gas is turned into liquefied natural gas (LNG) for shipment to markets. The captured CO2 is piped back out to sea for injection. This project was a major technological accomplishment for Statoil, which deployed innovative technologies, in a difficult and challenging environment; it is another good example of how technological advances allow for the extraction of oil and gas that only a short while ago people thought impossible.
Gorgon is the final and by far the biggest pioneer project, with construction costs exceeding $40 billion.7 Like Snohvit, it produces LNG. The project, led by Chevron, is located on Barrow Island, on the northwest shelf of Australia. The gas fields lie 130–220 km offshore and contain about 14 percent CO2. Shipping the first LNG in March 2016, planning and development of this project stretch back more than a quarter-century. Once operational, the CCS part of the project will store up to 4 million tonnes of CO2 per year in a sandstone formation 2.5 km below Barrow Island. The inclusion of CCS was a collaborative decision made by Chevron and the government of Australia; Chevron considered it part of the cost of doing business. While no law or regulation required CCS at Gorgon, there was still a general concern about greenhouse gas emissions, especially from a single source that would emit millions of tonnes of CO2 per year. While adding to the project costs, it was determined that the increase was acceptable.8
In the mid-2000s, in response to several government programs to help incentivize CCS deployment (see chapter 7), dozens of large-scale CCS projects were announced. As is typical for emerging technologies, most of these projects were never built. However, the foray helped move CCS technology forward and taught important lessons.9 The plants that were built demonstrated the diversity and potential of CCS. This section describes two projects in the industrial sector—Quest and Decatur—followed by three power sector projects in the next section: Boundary Dam, Kemper, and Petra Nova.
The amount of oil contained in the oil sands in Alberta, Canada, is second only to the amount of oil in Saudi Arabia. However, unlike Saudi oil, there is a big carbon footprint associated with the production of oil from these sands. This has resulted in policies to reject Alberta oil, ranging from California setting limits on the carbon footprint of imported oil, to efforts attempting to block the construction of the Keystone pipeline, which would carry Alberta oil to the US gulf coast refineries. As part of the effort to address these concerns, the Quest Carbon Capture and Storage project demonstrates how CCS can reduce the carbon footprint of the oil sands.10
Bitumen, a heavy and extremely viscous oil, is a product of the oil sands. To be used by refineries to produce fuels such as gasoline, bitumen is reacted with hydrogen to make a lighter oil in a process called upgrading. The Scotford Upgrader, located in Fort Saskatchewan, Alberta, can upgrade 255,000 bbls/day. The hydrogen is made from methane in a process called “steam methane reforming,” which produces CO2 as a by-product. At Scotford, an amine process captures about 35 percent of the CO2 produced by the reformer. The captured CO2—over a million tons per year—is piped 64 km and injected 2 km deep into a saline formation. The Quest project, which has been successfully operating since the fall of 2015, came in on time and under budget.
The Decatur Project in Decatur, Illinois, is really two projects. The first, called the Illinois Basin Decatur Project, injected a million tons of CO2 over a three-year period, from 2011 to 2014, as part of the US Department of Energy’s Regional Partnership Program.11 Archer Daniels Midland (ADM) leads the second and larger project, the Illinois Industrial CCS Project (ICCS), which started injecting a million tons per year in early 2017.
For both projects, the source of the CO2 is the ADM biofuel plant, where a very high-purity CO2 stream is a by-product of fuel-grade ethanol production via anaerobic fermentation of corn. The well permit for the first project was limited to a total injection of one million tons into the Mount Simon Sandstone at a depth of about 2 km. This pilot project allowed the researchers to characterize the storage reservoir and develop measurement, monitoring, and verification (MMV) protocols. The second project drilled two new injection wells under a Class VI permit from the US Environmental Protection Agency’s Underground Injection Control Program. This is the first project to operate under such a Class VI permit, created specifically for non-EOR CO2 injections. Since the biofuel plant produces a high purity CO2 by-product, the project costs are primarily due to compression, injection, and MMV; the CO2 is being stored directly under the site, so no pipeline costs are involved. A grant from the US government covered about two-thirds of the project costs.
This project was vetted and approved by the top management at ADM and was motivated by climate change concerns: “ADM, as part of its comprehensive strategy for energy sustainability and environmental responsibility, is implementing the Illinois ICCS project to reduce carbon footprint of industrial processes, e.g., by permanently storing the CO2 generated during ethanol production in deep underground rock formations, rather than releasing it into the atmosphere.”12
The first large-scale CCS demonstration project in the power sector came on-line in October 2014 at the Boundary Dam Power Station in Estevan, Saskatchewan, Canada. A post-combustion amine process captures the CO2 from the pulverized coal power plant. The net power output after capture is 110 MWe, with a capture rate between 85 and 90 percent. Most of the CO2 is sold for EOR and any unsold CO2 is injected into a nearby saline formation developed by the Aquistore Project, a CCS research project.13
The owner, SaskPower, needed to upgrade the boiler of Unit #3 at the plant, but Canada’s 2012 update to the Environmental Protection Act created a problem for them. The update requires new coal plants to comply with an emission limit of 420 tCO2/GWh of electricity produced. This limit would also apply to existing plants when they turn forty years old. Boundary Dam burned lignite coal with an emissions factor over 1000 tCO2/GWh. To make the investment worthwhile, the plant would have to operate past its fortieth birthday. SaskPower was left with two choices: either include CCS in their upgrade project, or shut down boiler Unit #3 and replace it with a gas turbine. They chose the first option.
Several factors played into SaskPower’s decision.14 Saskatchewan has a three-hundred-year supply of lignite that SaskPower does not want to strand. The project qualified for direct government subsidies of C$240 million, which represented over 20 percent of the initial projected project cost of C$1.1 billion. SaskPower could sell by-products for revenue, the biggest being CO2 for EOR. Other by-products were sulfuric acid sold for fertilizer and industrial applications, and fly ash for concrete production. Finally, they claimed that the fuel cost was significantly lower for lignite than natural gas. SaskPower argued that they were looking at a thirty-year timeframe, and estimated that natural gas prices over that period would be significantly higher than in 2014.
The final project cost approached C$1.5 billion, an overrun of almost C$400 million. Much of it was associated not with carbon capture, but with the revamp of the existing coal plant. Initially, there were problems with the capture unit meeting the specification for the capture rate. The cause was related to issues with the unit’s design; there were no fundamental issues related to the capture technology. After about a year, the issues were resolved and the plant is currently meeting its specifications. One major problem is still outstanding in 2018: a high solvent degradation rate. SaskPower thinks it may take a few years to resolve completely. The problem is very plant-specific, involving impurities in the flue gas, the specific amine solution chosen, and the capture system design. The Petra Nova project discussed below, which uses a different amine solution and has a different design, has reported no such problems.
Like Sleipner, Boundary Dam can claim a major milestone for carbon capture. Sleipner was the first million-tonne-a-year CCS project, while Boundary Dam was the first million-tonne-a-year CCS project at a power plant. While Boundary Dam did encounter some technical problems, this is to be expected for first-of-a-kind projects, as part of the learning process. All technical issues are now resolved or in the process of being resolved. Looking forward, SaskPower will need to make decisions about two other boiler units at Boundary Dam: whether to retrofit with CCS or repower with gas turbines. The technology has proven itself, so the final choice of how SaskPower proceeds will come down to economics. Based on the learnings of this project, SaskPower has stated that they can reduce costs by 20 to 30 percent for the next CCS retrofit project. However, their outlook on the future prices for natural gas will probably be the most important component in the economic analysis.
The start of the Kemper Project can be traced back to 2004, when Southern Company received an award from Clean Coal Power Initiative (CCPI), a program within the US DOE to help fund demonstration projects. The motivation behind this award was not CCS, but the desire to commercialize a new gasification technology called Transport Integrated Gasification (TRIG). A key feature of TRIG is that it can work well with low-rank coals like lignite. The gasifier had been under development for years by Southern Company and the US DOE, and a pilot plant of the gasification system was in operation at Southern’s Power Systems Development Facility in Wilsonville, Alabama.15
The original objective was to build a plant in Orlando, Florida; carbon capture was not part of this plan. When the environment for building a new coal plant in Florida became problematic, the project was moved to Kemper County, Mississippi, in 2008. Mississippi was a desirable venue because of the state’s interest in exploiting its hydrocarbon resources, specifically Mississippi lignite as power plant feedstock, and in capturing CO2 for EOR to produce Mississippi oil. Furthermore, the Mississippi Public Utilities Commission (PUC) was amenable to rate-base this project, thereby greatly helping Southern to finance it. Therefore, the project aligned well with Southern’s interest in demonstrating its TRIG technology, and the state of Mississippi’s interest in exploiting their natural resources. The project is designed to capture approximately 3.4 MtCO2/year for a capture rate of 65 percent.
Delays and escalating costs hampered the Kemper Project. The earliest cost estimates I am aware of are $2.2 billion for a 582 MWe (net) power plant producing 3.4 million metric tons of CO2 a year. These costs escalated to $7.5 billion. The cause of the cost increases is mostly unrelated to CCS; implementing multiple first-of-a-kind technologies and the complexity of integrating them are the underlying reasons for the cost overruns. Making the task even more difficult is the large jump in scale this project attempted, from a pilot plant up to nearly 600 MWe. On top of all of this, the plant construction has been hampered by very low labor productivity.
In June 2017, Southern abandoned the gasification part of the Kemper Project for economic reasons.16 The price of natural gas had fallen so much since the start of the project, it was determined that it would be cheaper to run the gas turbines on natural gas rather than the syngas from the gasifiers. Therefore, even though the commissioning of the gasification plant was just about complete, the low natural gas price has prevented it from operating. Since the capture system— which performed well in the commissioning tests—was part of the gasification plant, the CCS part of this project was no longer practicable.
The legacy of Kemper for the CCS world is to cast even more doubts on the gasification pathway. As discussed in chapter 3, it was not that long ago that the conventional wisdom said coal gasification with pre-combustion capture was the favored technology for a zero-emission coal-fired power plant. While there may still be a role for coal gasification in the future, the pendulum today has swung back to favor pulverized coal power plants with either post-combustion or oxy-combustion capture.
The Petra Nova Project outside of Houston, Texas, came on-line in late 2016, and is a joint venture between NRG and JX Nippon Oil and Gas Exploration.17 Like Boundary Dam, Petra Nova is a post-combustion amine capture process at a pulverized coal power plant; it captures 1.6 MtCO2/year for EOR from boiler flue gas associated with 240 MWe of power production. A unique feature of this project is that it is vertically integrated. Instead of simply selling the CO2 to EOR operators, Petra Nova bought their own oil field to operate.
Another unique feature of the project is how low-pressure steam is provided to the amine process. The standard design, as implemented at Boundary Dam, is to integrate the capture process with the power plant’s steam cycle. In Petra Nova’s case, the steam generation is from the exhaust of a gas turbine. This has the advantage of simplifying the plant design without losing power plant capacity, as happens when extracting steam from the power plant steam cycle. A disadvantage is that the gas turbine generates CO2 emissions that are not captured.
At initiation, this project aligned well with NRG’s business strategy. The CEO of NRG at that time was David Crane, who strongly felt the future was in clean energy. As he said in his resignation letter, “The new frontier of the energy business that I pushed the company into, [was] then, and [is] still now, in the long-term best interest of the company's employees, its shareholders, its customers and the earth we all inhabit. As a company that aspires to growth, there is no growth in our sector outside of clean energy; only slow but irreversible contraction following the path of fixed-line telephony.”18
The project cost $1 billion, which included the expense of an approximately 140 km long pipeline. The project was awarded $190 million from the CCPI and is eligible for 45Q tax credits (see chapter 7). A major financial driver is the revenue from selling oil produced by EOR. The big drop in oil price from the project planning to plant start-up will have a significant impact on the bottom line. In fact, it is questionable whether the project would have been undertaken with these lower oil prices.
Unlike the Southern and SaskPower projects, which occurred in regulated markets, the NRG project occurred in a deregulated market. As a result, NRG wanted to reduce risk as much as possible, so they chose a well‐understood and proven technology. The amine system vendor was Mitsubishi Heavy Industries (MHI), who tested the amine at a pilot plant at Southern Company’s Plant Berry in Alabama for over a year. Unlike Boundary Dam, there have been no problems reported in the capture system operation at Petra Nova, which came in on time and on budget and has been operating smoothly in its first year. This is a major accomplishment for NRG and its partners, as well as CCS in general.