The objective of this study is to conduct a critical evaluation of the environmental law framework applicable to carbon capture and storage (hereafter CCS) in South Africa. The discussion begins by confirming that CCS has a place in environmental law as a mitigation measure. The inclusion of CCS in the clean development mechanism could incentivise the development of environmental law frameworks for CCS in South Africa. Implementation of CCS is gradual, with only eight large scale integrated CCS projects having been established around the world. An appreciation of key scientific concepts is helpful for an understanding of the CCS process. The CCS project life cycle and related impacts on the environment provide a context for discussion of the legal requirements accompanying the CCS life cycle. The Constitution of the Republic of South Africa, 1996 and the National Environmental Management Act 107 of 1998 constitute appropriate framework legislation for CCS. Decision 3/CMP.1, Modalities and procedures for a clean development mechanism as defined in Article 12 of the Kyoto Protocol adopted by the Conference of the Parties serving as the Meeting of the Parties to the Kyoto Protocol held at Montreal from 28 November to 10 December 2001 March 2006 provides international legal requirements accompanying the project life cycle against which the South African legal framework is examined. Some provisions of additional South African laws and policies will be applicable to CCS depending on the nature of the specific CCS project, but specific regulations may have to be developed for South Africa. Policy documents have been gradually bringing clarity to the way forward in arriving at a legal framework for CCS, and by reference to existing local legislation and international guidance, an environmental law framework for CCS can be developed for South Africa. / LLM (Environmental Law and Governance), North-West University, Potchefstroom Campus, 2014

Thesis (MScEng)--Stellenbosch University. / ENGLISH ABSTRACT: Carbon dioxide (CO2) is classified as the main greenhouse gas (GHG) contributing to global warming. Estimates by the Intergovernmental Panel on Climate Change (IPCC) suggest that CO2 emissions must be reduced by between 50 to 85% by 2050 to avoid irreversible impacts. Carbon capture and storage (CCS) strategies can be applied to de-carbonize the emissions from fossil-fueled power plants. Compared to other CCS techniques, post-combustion capture (PCC) is most likely to be implemented effectively as a retrofit option to existing power plants. At present however CCS is not yet commercially viable. The main challenge with CCS is to reduce the inherent energy penalty of the CO2 separation stage on the host plant. Seventy-five to eighty percent of the total cost of CCS is associated with the separation stage. There are several technologies available for separating CO2 from power plant flue gas streams. Reactive absorption with aqueous amine solutions has the ability to treat low concentration, low pressure and large flux flue gas streams in industrial-scale applications. It is most likely to be the first technology employed commercially in the implementation of CCS. The energy required for solvent regeneration however, is high for the standard solvent used in reactive absorption processes, i.e. MEA. This leads to a reduction in thermal efficiency of the host plant of up to 15%. Alternative solvent formulations are being evaluated in an attempt to reduce the energy intensity of the regeneration process. The main objective of this study was to establish a novel, simplified thermodynamic method for solvent screening. Partial solubility parameters (PSPs) were identified as the potential basis for such a method. The major limitation of this approach is that the model doesn’t account for effects from chemical reaction(s) between materials, e.g. CO2 reacting with aqueous alkanolamine solutions; considering only the effects from dissolution. The EquiSolv software system was developed based on PSP theory. The Hansen 3-set PSP approach was used to describe the equilibrium behaviour of CO2 absorbing in task specific solvents. The Hansen theory was expanded to a 4-set approach to account for contributions from electrostatic interactions between materials. The EquiSolv program was used successfully to screen large sets of solvent data (up to 400 million formulations) in the search for suitable alternative solvent formulations for CO2 absorption. The secondary objective of this study was to evaluate the ability of the proposed PSP model to accurately predict suitable alternative solvents for CO2 absorption through preliminary experimental work. A series of CO2 absorption experiments were conducted to evaluate the absorption performance of predicted alternative solvent formulations. The predicted alternative solvent formulations exhibited a significant improvement in absorption performance (up to a 97% increase in the measured absorption capacity) compared to conventional solvent formulations. Statistical analysis of the experimental results has shown that there is a statistically significant concordant relationship between the predicted and measured rankings for the absorption performance of the predicted solvent formulations. Based on this it was concluded that PSP theory can be used to accurately predict the equilibrium behaviour of CO2 absorbing in task specific solvents. Recently ionic liquids (ILs) have been identified as potential alternatives to alkanolamine solutions conventionally used for CO2 absorption. Absorption experiments were conducted as a preliminary assessment of the absorption performance of ILs. Results have shown ILs to have significantly improved performance compared to conventional alkanolamine solvents; up to a 96% increase in the measured absorption capacity compared to conventional solvents. Future work should focus on developing task specific ionic liquids (TSILs) in an attempt to reduce the energy intensity of solvent regeneration in CO2 absorption processes. / AFRIKAANSE OPSOMMING: Koolsuurgas (CO2) word geklassifiseer as die vernaamste kweekhuis gas (GHG) wat bydra to globale verwarming. Beramings deur die Interregeringspaneel oor Klimaatsverandering (IPKV) toon aan dat CO2 emissies teen 2050 verminder moet word met tussen 50 en 85% om onomkeerbare invloede te vermy. Verskeie koolstof opvangs en bergings (KOB) strategieë kan toegepas word ten einde die koolstof dioksied konsentrasie in die emissies van kragstasies wat fossielbrandstowwe gebruik, te verminder. Naverbranding opvangs (NVO) is die mees aangewese KOB tegniek wat effektief toegepas kan word op bestaande kragstasies. Tans is KOB egter nog nie kommersieël lewensvatbaarvatbaar nie. Die hoof uitdaging wat KOB in die gesig staar is om die energie boete inherent aan die CO2 skeidingstap te verminder. Tussen vyf-en-sewentig en tagtig persent van die totale koste van KOB is gekoppel aan die skeidingstap. Daar is verskeie metodes beskikbaar vir die skeiding van CO2 uit die uitlaatgasse van kragstasies. Reaktiewe absorpsie met waterige oplossings van amiene kan gebruik word om lae konsentrasie, lae druk en hoë vloei uitlaatgasstrome in industriële toepassings te behandel. Dit is hoogs waarskynlik die eerste tegnologie wat kommersieël aangewend sal word in die toepassing van KOB. Die oplosmiddel wat normalweg vir reaktiewe absorpsie gebruik word (d.w.s. MEA) benodig egter ‘n groot hoeveelheid energie vir regenerasie. Dit lei tot ‘n afname in die termiese doeltreffendheid van die voeder aanleg van tot 15%. Alternatiewe oplosmiddelstelsels word tans ondersoek in ‘n poging om the energie intensiteit van die regenerasieproses te verminder. Die hoof doelwit van hierdie studie was om ‘n nuwe, ongekompliseerde termodinamiese metode te vestig vir die keuring van alternatiewe oplosmiddels. Parsiële oplosbaarheidsparameters (POPs) is geïdentifiseer as ‘n moontlike grondslag vir so ‘n metode. Die model beskryf egter slegs die ontbindings gedrag van materiale. Die effekte van chemise reaksie(s) tussen materiale, bv. die tussen CO2 en waterige oplossings van alkanolamiene, word nie in ag geneem nie. Die POP teorie het gedien as grondslag vir die ontwerp van die EquiSolv sagteware stelsel. Die Hansen stel van drie POPs is gebruik om die ewewigsgedrag te beskryf van CO2 wat absorbeer in doelgerig-ontwerpte oplosmiddels. Die Hansen teorie is verder uitgebrei na ‘n stel van vier POPs om die bydrae van elektrostatiese wisselwerking tussen materiale in ag te neem. Die EquiSolv program is verskeie kere met groot sukses gebruik vir die sifting van groot stelle data (soveel as 400 miljoen formulasies) in die soektog na alternatiewe oplosmiddels vir CO2 absorpsie. Die sekondêre doelwit van die studie was om die vermoë van die voorgestelde POP model om geskikte alternatiewe oplosmiddels vir CO2 absorpsie akkuraat te voorspel, te ondersoek deur voorlopige eksperimentele werk. ‘n Reeks CO2 absorpsie eksperimente is gedoen ten einde die absorpsie werkverrigting van die voorspelde alternatiewe oplosmidels te ondersoek. ‘n Verbetering in absorpsie werkverrigting van tot 97% is gevind vir die voorspelde oplosmiddels vergeleke met die van oplosmiddels wat tipies in die industrie gebruik word. Statistiese ontleding van die eksperimentele resultate het getoon dat daar ‘n beduidende ooreenstemming tussen die voorspelde en gemete rangskikking van die voorspelde oplosmiddels se werkverrigting bestaan. Dus kan POP teorie gebruik word om die absorpsie van CO2 in doelgerig-ontwerpte oplosmiddels akkuraat te beskryf. Ioniese vloeistowwe (IVs) is onlangs geïdentifiseer as moontlike alternatiewe oplosmidels vir die alkanolamien oplossings wat normaalweg gebruik word vir CO2 absorpsie. Absorpsie eksperimente is gedoen ten einde ‘n voorlopige raming van die absorpsie werkverrigting van IVs te bekom. Daar is bevind dat IVs ‘n beduidende verbetering in werkverrigting toon in vergelyking met die alkanolamien oplosmiddels wat normaalweg gebruik word. ‘n Verbetering in absorpsie werkverrigting van tot 96% is gevind vir die voorspelde IV-bevattende oplosmiddels vergeleke met die van oplosmiddels wat tipies in die industrie gebruik word. Die fokus van toekomstige navorsing moet val op die ontwikkeling van doelgemaakte ioniese vloeistowwe (DGIVs) in ‘n poging om die energie intensiteit van oplosmiddel regenerasie in CO2 absorpsie prosesse te verminder.

This dissertation presents a fibre-optic sensing approach to provide continuous measurements of CO2 concentration at discrete points under typical conditions of geological CO2 storage. Carbon capture and storage is considered to have potential for a large-scale reduction in CO2 emissions in a relatively short period of time while other solutions to replace fossil fuels are being investigated. One significant drawback of carbon capture and storage is the possibility of long-term CO2 leakage. Therefore, the development of reliable technology for monitoring, verification, and accounting of geological CO2 storage is critical to fulfill safety regulations and achieve public acceptance. The major limitations of current technology include relatively low resolutions, high costs, and the lack of continuous monitoring for long periods of time. To address these limitations, two types of fibre-optic sensors are investigated, namely long period gratings and Mach-Zehnder interferometers. The sensing principle for CO2 detection is based on the sensitivity of these sensors to the refractive index of the medium that surrounds the fibre. Fibre-optic sensors are attractive for downhole applications due to the possibility of fabricating inexpensive high resolution devices that are able to operate in harsh environments over long periods of time. This dissertation focuses on increasing the refractive index sensitivity of long period gratings and Mach-Zehnder interferometers by applying coatings that have a high refractive index. The dip-coating method is used to coat long period gratings with polystyrene, and the sensitivity at low refractive indices is increased by tuning coating thickness. The results show that long period gratings coated with polystyrene are able to detect CO2 in gaseous and aqueous media. This work reports the first measurement of CO2 dissolution in water at high pressure with a fibre-optic sensor. Additionally, atomic layer deposition is investigated to coat long period gratings and Mach-Zehnder interferometers with hafnium oxide. The study of this coating technique aims to address the main limitation of the dip-coating method: the challenge to achieve precise control over coating thickness. The results show that atomic layer deposition is suitable to maximize the sensitivity of long period gratings and Mach-Zehnder interferometers at a target refractive index. / Graduate / 0548 / 0752 / 0799 / luismelo@uvic.ca

No description available.

The Intergovernmental Panel on Climate Change (2001) reports that increased anthropogenic greenhouse gas (GHG) emissions, of which carbon dioxide (CO2) is the main component, have caused the Earths temperature to rise. Therefore, it is necessary to find ways to reduce GHG emissions and to deal with the emissions that continue to be produced. Carbon capture and storage (CCS) is one method that is being considered to deal with GHG emissions, specifically CO2 emissions. The basic idea behind CCS is that CO2 is captured from a point source, such as a power plant, and is then transported to a storage site (e.g., an oil or gas reservoir), where it is subsequently stored. The International Energy Agency Greenhouse Gas Programme (IEA GHG) began a CO2 geological sequestration pilot project in 2000 in Weyburn, Saskatchewan as part of an enhanced oil recovery project operatedby Cenovus (formerly EnCana) in the Weyburn Field (White et al. 2004). The research presented in this thesis evaluates the sealing potential of the Lea Park Formation in the Weyburn Field by determining its permeability and CO2 breakthrough pressure. In this context, breakthrough pressure describes the differential pressure between a wetting phase (e.g., formation brine) and a non-wetting phase (e.g., CO2) that is sufficient to enable the non-wetting phase to form a connected flow system across a given volume of porous medium (e.g., a rock sample). A new system for measuring the permeability and CO2 breakthrough pressure of shales was developed in this research. The development effort included extensive trouble-shooting and, ultimately, the development of sample preparation and testing procedures. The new system was used to conduct permeability and CO2 breakthrough pressure tests on shale samples from the Lea Park Formation (i.e., Lea Park shale) and the Colorado Group (i.e., Colorado shale). Permeability results for samples from the Lea Park shale ranged from 14 to 35 nd (1410-21 to 3510-21 m2), and between eight and 46 nd (810-21 to 4610-21 m2) for the Colorado shale. A CO2 breakthrough pressure for the Lea Park shale was determined to be 0.02 MPa, while values of 0.02 and 2.7 MPa were measured for the Colorado shale. The CO2 breakthrough pressure test results indicate that the Lea Park shale will not withstand large pressures before allowing CO2 to flow through it. However, the permeabilities are extremely low; hence the rate of flow would be low. In other words, the low permeability of the Lea Park shale will be the controlling factor in terms of the rate of potential CO2 leakage through it. Calculations based on the properties measured in this research suggest that the time required for CO2 to flow from the base to the top of the Lea Park Formation would be on the order of ten thousand years. Based on diffusion coefficients published for other shales, calculations suggest that CO2 leakage via chemical diffusion would be several times slower leakage via hydraulically-driven flow.

The Intergovernmental Panel on Climate Change (2001) reports that increased anthropogenic greenhouse gas (GHG) emissions, of which carbon dioxide (CO2) is the main component, have caused the Earths temperature to rise. Therefore, it is necessary to find ways to reduce GHG emissions and to deal with the emissions that continue to be produced. Carbon capture and storage (CCS) is one method that is being considered to deal with GHG emissions, specifically CO2 emissions. The basic idea behind CCS is that CO2 is captured from a point source, such as a power plant, and is then transported to a storage site (e.g., an oil or gas reservoir), where it is subsequently stored. The International Energy Agency Greenhouse Gas Programme (IEA GHG) began a CO2 geological sequestration pilot project in 2000 in Weyburn, Saskatchewan as part of an enhanced oil recovery project operatedby Cenovus (formerly EnCana) in the Weyburn Field (White et al. 2004). The research presented in this thesis evaluates the sealing potential of the Lea Park Formation in the Weyburn Field by determining its permeability and CO2 breakthrough pressure. In this context, breakthrough pressure describes the differential pressure between a wetting phase (e.g., formation brine) and a non-wetting phase (e.g., CO2) that is sufficient to enable the non-wetting phase to form a connected flow system across a given volume of porous medium (e.g., a rock sample). A new system for measuring the permeability and CO2 breakthrough pressure of shales was developed in this research. The development effort included extensive trouble-shooting and, ultimately, the development of sample preparation and testing procedures. The new system was used to conduct permeability and CO2 breakthrough pressure tests on shale samples from the Lea Park Formation (i.e., Lea Park shale) and the Colorado Group (i.e., Colorado shale). Permeability results for samples from the Lea Park shale ranged from 14 to 35 nd (1410-21 to 3510-21 m2), and between eight and 46 nd (810-21 to 4610-21 m2) for the Colorado shale. A CO2 breakthrough pressure for the Lea Park shale was determined to be 0.02 MPa, while values of 0.02 and 2.7 MPa were measured for the Colorado shale. The CO2 breakthrough pressure test results indicate that the Lea Park shale will not withstand large pressures before allowing CO2 to flow through it. However, the permeabilities are extremely low; hence the rate of flow would be low. In other words, the low permeability of the Lea Park shale will be the controlling factor in terms of the rate of potential CO2 leakage through it. Calculations based on the properties measured in this research suggest that the time required for CO2 to flow from the base to the top of the Lea Park Formation would be on the order of ten thousand years. Based on diffusion coefficients published for other shales, calculations suggest that CO2 leakage via chemical diffusion would be several times slower leakage via hydraulically-driven flow.

Geologic sequestration of carbon dioxide (CO 2) in a deep, saline aquifer is being proposed for a power-generating facility in Florida as a method to mitigate contribution to global climate change from greenhouse gas (GHG) emissions. The proposed repository is a brine-saturated, dolomitic-limestone aquifer with anhydrite inclusions contained within the Cedar Keys/Lawson formations of Central Florida. Thermodynamic modeling is used to investigate the geochemical equilibrium reactions for the minerals calcite, dolomite, and gypsum with 28 aqueous species for the purpose of determining the sensitivity of mineral precipitation and dissolution to the temperature and pressure of the aquifer and the salinity and initial pH of the brine. The use of different theories for estimating CO2 fugacity, solubility in brine, and chemical activity is demonstrated to have insignificant effects on the predicted results. Nine different combinations of thermodynamic models predict that the geochemical response to CO2 injection is calcite and dolomite dissolution and gypsum precipitation, with good agreement among the quantities estimated. In all cases, CO2 storage through solubility trapping is demonstrated to be a likely process, while storage through mineral trapping is predicted to not occur. Over the range of values examined, it is found that net mineral dissolution and precipitation is relatively sensitive to temperature and salinity, insensitive to CO2 injection pressure and initial pH, and significant changes to porosity will not occur.

Many geoscientists endorse Carbon Capture and Storage (CCS) as a potential strategy for mitigating emissions of greenhouse gases. Deep saline aquifers have been reported to have larger CO 2 storage capacity than other formation types because of their availability worldwide and less competitive usage. This work proposes an analytical model for screening potential CO 2 storage sites and investigates injection strategies that can be employed to enhance CO 2 storage. The analytical model provides of estimates CO 2 storage efficiency, formation pressure profiles, and CO 2 –brine interface location. The results from the analytical model were compared to those from a sophisticated and reliable numerical model (TOUGH 2 ). The models showed excellent agreement when input conditions applied in both were similar. Results from sensitivity studies indicate that the agreement between the analytical model and TOUGH2 strongly depends on irreducible brine saturation, gravity and on the relationship between relative permeability and brine saturation. A series of numerical experiments have been conducted to study the pros and cons of different injection strategies for CO 2 storage in confined saline aquifers. Vertical, horizontal, and joint vertical and horizontal injection wells were considered. Simulations results show that horizontal wells could be utilized to improve CO 2 storage capacity and efficiency in confined aquifers under pressure-limited conditions with relative permeability ratios greater than or equal to 0:01. In addition, joint wells are more efficient than single vertical wells and less efficient than single horizontal wells for CO 2 storage in anisotropic aquifers.

Carbon capture and storage technologies are necessary to start lowering greenhouse gas emissions while continuing to utilize existing thermal power generation infrastructure. Calcium looping is a promising technology based on cyclic calcination/carbonation reactions which utilizes limestone as a sorbent. Steam is present in combustion flue gas and in the calciner used for sorbent regeneration. The effect of steam during calcination on sorbent performance has not been extensively studied in the literature. Here, experiments were conducted using a thermogravimetric analyzer (TGA) and subsequently a dual-fluidized bed pilot plant to determine the effect of steam injection during calcination on sorbent reactivity during carbonation. In a TGA, various levels of steam (0-40% vol.) were injected during sorbent regeneration throughout 15 calcination/carbonation cycles. All concentrations of steam were found to increase sorbent reactivity during carbonation. A level of 15% steam during calcination had the largest impact. Steam changes the morphology of the sorbent during calcination, likely by shifting the pore volume to larger pores, resulting in a structure which has an increased carrying capacity. This effect was then examined at the pilot scale to determine if the phase contacting patterns and solids heat-up rates in a fluidized bed were factors. Three levels of steam (0%, 15%, 65%) were injected during sorbent regeneration throughout 5 hours of steady state operation. Again, all levels of steam were found to increase sorbent reactivity and reduce the required sorbent make-up rate with the best performance seen at 65% steam.

Carbon capture and storage (CCS) and a point of electricity generation is a promising option for mitigating greenhouse gas emissions. One issue with respect to CCS is the design of carbon dioxide transport, storage and injection system. This dissertation develops a model, OptimaCCS, that combines economic and spatial optimization for the integration of CCS transport, storage and injection infrastructure to minimize costs. The model solves for the lowest-cost set of pipeline routes and storage/injection sites that connect CO2 sources to the storage. It factors in pipeline costs, site-specific storage costs, and pipeline routes considerations involving existing right of ways and land use. It also considers cost reductions resulting from networking the pipelines segment from the plants into trunk lines that lead to the storage sites. OptimaCCS is demonstrated for a system involving carbon capture at 14 Texas coal-fired power plants and three potential deep-saline aquifer sequestration sites. In turn OptimaCCS generates 1) a cost-effective CCS pipeline network for transporting CO2 from all the power plants to the possible storage sites, and 2) an estimate of the costs associated with the CO2 transport and storage. It is used to examine variations in the configuration of the pipeline network depending on differences in storage site-specific injection costs. These results highlight how various levels of cooperation by CO2 emitters and difference in injection costs among possible storage sites can affect the most cost-effective arrangement for deploying CCS infrastructure. This study also analyzes CCS deployment under the features in a piece of legislation the draft of American Power Act (APA) - that was proposed in 2010 which contained a goal of CCS capacity for emissions from 72 Gigawatt (GW) by 2034. A model was developed that simulates CCS deployment while considering different combinations of carbon price trajectories, technology progress, and assumed auction prices. The model shows that the deployment rate of CCS technology under APA is affected by the available bonus allowances, carbon price trajectory, CCS incentive, technological adaptation, and auction process. Furthermore it demonstrates that the 72GW objective can only be achieved in a rapid deployment scenario with quick learning-by-doing and high carbon price starting at 25 dollars in 2013 with a 5 percent annual increase. Furthermore under the slow and moderate deployment scenarios CCS capacity falls short of achieving the 72 GW objective.