Search

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO 2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO 2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO 2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO 2 geologic sequestration (75 FR 77230). [ABSTRACT FROM AUTHOR]

Abstract: In 2007, the Norwegian prime minister made the promise that a ‘lunar landing’ was due at Mongstad Refining in 2014, involving full-scale cleaning of CO2. This was the prelude to a long and heated debate on Carbon Capture and Storage (CCS) in Norwegian media. Through a discourse analysis we have identified two main media discourses related to the announced lunar landing; including important participants and arguments, as well as the positions taken by the actors of the discourses. The paper outlines the underlying structures of the public debate about CCS, and argues that the discourse is not really about CCS but politics in the form of narratives on promises, alliances and emotions caused by political actions. The paper shows the importance of media discourses for the legitimacy and willingness to finance CCS R&D. [Copyright &y& Elsevier]

Abstract: This paper describes an operability analysis and control structure design for handling membrane leakage in a hydrogen membrane reactor (HMR) as used in an integrated reforming combined power cycle (IRCC) based on natural gas as fuel. For this type of reforming to be competitive to power generation with carbon capture, low costs and emission of CO2 and NOx is required. Further, high operability and robustness is also required. This is achieved through an understanding of the system dynamics and robust control structure design. The overall aim of the work is to improve the operability of such gas power plants under membrane leakage, which may cause detrimental hot areas in the reactor. Good operability means essentially that a plant can be operated easily, i.e. it can cope with disturbances, offsets and other uncertainties with the smallest possible profit loss and without frequent shutdowns. This is obtained both through design of the process itself and design of the control system. An important ingredient is the use of a dynamic, control relevant simulation model. The paper presents an analysis of how the control objective affects the choice of control structure for the HMR process and the control performance under membrane leakage. Also, the effect on CO2 capture is shown. [Copyright &y& Elsevier]

Abstract: The increasing atmospheric carbon dioxide concentration has lead to concerns about global warming. One of the options that can contribute to the reduction of carbon dioxide emissions is CO2 sequestration by mineral carbonation. In this paper we will present a model of an oxyfuel combustion process integrated into a carbonation process using Mg(OH)2 produced from magnesium silicate mineral. Therefore, the objective of this work is to develop integrated carbon dioxide capture and storage methods for an oxyfuel combustion process where CO2 will be captured directly from the flue gas in a carbonation reactor. There it reacts with injected magnesium hydroxide Mg(OH)2 solid, with thermodynamically stable MgCO3 as the final product. In this paper we will present a process model that illustrates how the carbonation process integrated into oxyfuel combustion could be an alternative process for oxyfuel combustion followed by geological storage of CO2. We will also present a simulation model for this process by using Aspen Plus® simulation software. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) has been identified as a critical enabling technology to mitigate the large quantities of carbon dioxide (CO2) emitted from coal-fired power plants and subsequently discharged to the atmosphere. While large-scale CO2 injection in geologic formations associated with enhanced oil recovery operations have been ongoing for over 30 years, different technical challenges face the injection of CO2 into saline reservoirs sourced from utility boilers. Beyond the high costs of capture, operational reliability related to the integration of capture with pipeline transport and injections are components of CCS with very little operational experience. Some issues unique to utility boiler capture include planned and forced outages, generation loading, and changes in CO2 purity. These operational issues can only be resolved through the integration of capture, transportation, and injection operations in demonstration-scale projects. Parametric testing provides an opportunity to evaluate how the integration of transportation and injection for storage respond to changes in plant operations. This paper will introduce a CCS demonstration-scale research program that involves a carbon capture unit designed to supply up to 500 metric tons (tonnes) per day (182,500 tonnes per year), a 19-kilometer pipeline and injection into a subsurface saline reservoir located at 3,060 meters below ground surface. The project will provide a test bed to begin to understand and resolve the challenges of integrating the key components of CCS with utility boilers. The paper will provide an update on the status of the project, covering the permits required to get the demonstration in motion, the geologic assessment of the proposed injection target reservoirs, and the engineering design for the injection and monitoring program. [Copyright &y& Elsevier]

Abstract: With the increasing concern about climate change, the public, industry and government are showing increased interest towards reduction of CO2 emissions. Geological storage of CO2 is perceived to be one of the most promising methods that could allow significant reduction in CO2 emissions over the short and medium term. One major concern against geological storage of CO2 is the possibility of its leakage. Carbon dioxide under the pressure and temperature conditions encountered in typical deep aquifers remains more buoyant than water. One process that could lead to permanent trapping of CO2 is one that includes geochemical reactions leading to the formation of solid minerals. However, the time-scale of such reactions is perceived to be centuries to millennia. In contrast, the kinetics of CO2-hydrate formation–that leads to trapping of CO2 in the solid form–is quite fast, providing the opportunity for secure storage of CO2. In this paper and its companion, two different geological settings that are suitable for formation of CO2 hydrate are investigated. In this paper storage of CO2 beneath the ocean floor is studied, while storage in depleted gas reservoirs is studied in the companion paper. It has been suggested that CO2 may be accumulated in the depressions on the ocean floor, where pressure and temperature conditions are such that either liquid CO2 would accumulate or CO2 hydrates would form. However, there have been significant concerns about the accompanying change in pH and its adverse effect on the ocean ecosystem. In this paper, permanent trapping of CO2 at a depth of a few hundred meters beneath the ocean floor, where the CO2 is thought to be of little or no harm to the ocean ecosystem, is studied. Based on density calculations, Schrag and his co-workers have shown that for oceans that are deeper than approximately, CO2 density at the ocean floor is more than the surrounding water. With increased depth below the ocean floor and as a result of increased temperature, the density of CO2 reduces faster than that of water such that at some depth below the ocean floor, CO2 will be lighter than the surrounding water. Injection of CO2 at such depths or deeper intervals will lead to rise of the CO2 until it arrives at a depth where its density becomes heavier than water. The zone above this depth, where CO2 becomes heavier than water is called the negative buoyancy zone. Beneath the negative buoyancy zone, the CO2 is naturally trapped by a gravity barrier. Furthermore, as CO2 is rising towards this depth, it could pass through conditions where CO2 hydrates form. Formation of CO2 hydrate will further reduce formation permeability and introduce a second barrier against CO2 rise, even before it arrives at the boundary of the negative buoyancy zone. Under dynamic conditions of injection and hydrate formation, the initial state of pressure and temperature is perturbed, affecting the negative buoyancy zone. Simulation studies are presented to investigate (i) the changes in pressure as a result of injection that could push CO2 upwards into the negative buoyancy zone, and (ii) the increase in temperature as a result of formation of hydrates. Through a case study, we report numerical simulation studies that indicate that injection of CO2 at a depth of approximately 800 m below the ocean floor leads to the rise of CO2 until a depth of approximately 360 m below the ocean floor, where hydrates will form reducing the formation permeability. Any CO2 that might migrate further upwards could do so for another 135 m before it arrives at the negative buoyancy zone. These simulation studies suggest that total CO2 emissions of large power plants may be stored at such a site. [Copyright &y& Elsevier]

Abstract: The significant CO2 pipeline and CO2 injection well infrastructure developed in the United States over four decades of underground injections of CO2 for Enhanced Oil Recovery (“EOR”) operations was accompanied by development of a legal and regulatory framework for the incidental geologic storage of CO2 during EOR operations. That framework currently forbids incremental injections of anthropogenic CO2 beyond those required for oil recovery but that could be injected for the sole purpose of reducing atmospheric emissions of CO2. This paper summarizes some key aspects of the current legal and regulatory framework applicable to the transportation and underground injection of CO2 in connection with EOR operations and identifies those elements that are adequate to support CO2 transport and injection for carbon capture and storage (“CCS”) purposes. The paper next discuses regulatory changes underway that are intended to fill the regulatory gaps to allow for incremental injections of CO2 in the CCS context. Particular attention is paid to the current rulemaking proceedings before the USA Environmental Protection Agency governing permitting of CO2 injection wells for CCS purposes as well as some approaches to addressing potential regulation of CO2 pipelines and related matters. In concluding, the paper seeks briefly review the status of transposition of the European Union’s CCS Directive into binding national norms and points out some contrasts with the USA experience due to the absence of an EOR industry in Europe. [Copyright &y& Elsevier]

Abstract: Climate change mitigation is a dynamic area that, as it is addressed, brings new challenges to other environmental aspects. Carbon capture and storage (CCS) plants are the latest development in a series of environmental controls and have some distinctive features that could potentially lead to other wider environmental problems. Whilst CCS represents a significant step towards cutting greenhouse gas emissions, consideration needs to be given to the potential wider environmental consequences especially in terms of pollutant emissions and local air quality impacts. Challenges remain for existing plants which will need to consider the most cost-effective strategies for installation of CCS plant balanced against managing air quality impacts as dispersion characteristics change. In the case of post-combustion carbon dioxide (CO2) capture technology, which is the focus of this paper, removal of CO2 from the main flue gas stream requires diversion of the flue gas through the CCS process, before it arrives at the exhaust stack. This flue gas stream may be all or part of the total plant flow or for multi-unit plants may be diverted from specific power generation units into the CCS plant before exhausting to atmosphere, either through returning back to the existing stack or through a new dedicated stack. This diversion and subsequent emission in itself poses an engineering challenge. In particular, the integration of the CCS process with the existing plant must also ensure that the diverted flue gas still achieves adequate dispersion as it contains residual levels of pollutants such as nitrogen oxides (NOx) and sulphur dioxide (SO2), despite the fact that the CCS process itself may reduce some of these pollutant levels further as a process by-product. Power plants which incorporate CCS will still be required to adhere to the appropriate pollutant emission limits and ensure effective dispersion to minimise the risk of breaching local air quality standards. This paper draws on experience gained through post-combustion CCS projects and addresses the potential effects of CCS on air quality, in the case of carbon capture retrofits. The findings of this paper are relevant to project developers, power generators and policymakers globally who have an interest in the potential for CCS to provide an emissions abatement option for existing thermal assets in the short and long term. [Copyright &y& Elsevier]

Abstract: With the growing concern about climate change, interest towards reducing CO2 emissions has increased. Geological storage of CO2 is perceived to be one of the most promising methods that could provide significant reduction in CO2 emissions over the short and medium term. Since a major concern regarding geological storage is the possibility of leakage, trapping CO2 in the solid form is quite attractive. Unlike mineral trapping, the kinetics of CO2-hydrate formation is quite fast, providing the opportunity for long-term storage of CO2. In this paper, we study storage of CO2 at conditions similar to those at depleted gas pools of Northern Alberta. Thermodynamic calculations suggest that CO2 hydrate is stable at temperatures that occur in a number of formations in Northern Alberta, in an area where significant CO2 emissions are associated with production of oil sands and bitumen. Numerical simulation results presented in this paper suggest that, upon CO2 injection into such depleted gas reservoirs, pressure would initially rise until conditions are appropriate for hydrate formation, enabling storage of large volumes of CO2 in solid form. These results show that, because of tight packing of CO2 molecules in the solid (hydrate), the CO2 storage capacity of these pools is many times greater than their original gas-in-place. This provides a local option for storage of a portion of the CO2 emissions there. [Copyright &y& Elsevier]

Abstract: As CO2 is injected into a deep saline aquifer, three regions develop: A “drying” region next to the well in which CO2 injectate occupies 100% of the pore space, a brine region away from the injection well in which 100% of the pores are saturated with brine, and a two-phase region in which water and CO2 coexist. Several papers describe the speeds at which those two fronts progress outward using the Buckley-Leverett fractional flow (BLFF) theory. Next to a CO2 injection well and at early times, compositional flow theory must be implemented. It is also understood that far from the injection site, where only slight pressure elevation is felt, a single phase flow approach is sufficient because all the complexities of compositional flow could be neglected. However regulators may be wary of complex models and of the associated black box syndrome and rather may favor the simpler single-phase flow approach. This paper investigates using single-phase flow numerical models to describe compositional flow processes. Previous work already showed that results from the CMG-GEM and MODFLOW numerical codes are very similar away from the injection zone given some minor modifications in the input file of the single-phase flow code. We present a more thorough scoping analysis aiming at establishing the proposition that single-phase flow models (CMG-IMEX), given some simple treatment, can predict pressure increase as well as more complex compositional flow models (CMG-GEM). [Copyright &y& Elsevier]