Wellbore integrity analysis of a natural CO2 producer

Long-term integrity of existing wells in a CO₂-rich environment is essential for ensuring that geological sequestration of CO₂ will be an effective technology for mitigating greenhouse gas-induced climate change. The potential for wellbore leakage depends in part on the quality of the original construction as well as geochemical and geomechanical stresses that occur over its life-cycle. Field data are essential for assessing the integrated effect of these factors and their impact on wellbore integrity, defined as the maintenance of isolation between subsurface intervals. In this report, we investigate a 30-year-old well from a natural CO₂ production reservoir using a suite of downhole and laboratory tests to characterize isolation performance.These tests included mineralogical and hydrological characterization of 10 core samples of casing/cement/formation, wireline surveys to evaluate well conditions, fluid samples and an in situ permeability test. We find evidence for CO₂ migration in the occurrence of carbonated cement and calculate that the effective permeability of an 11′-region of the wellbore barrier system was between 0.5 and 1 milliDarcy. Despite these observations, we find that the amount of fluid migration along the wellbore was probably small because of several factors: the amount of carbonation decreased with distance from the reservoir, cement permeability was low (0.3–30 microDarcy), the cement–casing and cement-formation interfaces were tight, the casing was not corroded, fluid samples lacked CO₂, and the pressure gradient between reservoir and caprock was maintained. We conclude that the barrier system has ultimately performed well over the last 3 decades. These results will be used as part of a broader effort to develop a long-term predictive simulation tool to assess wellbore integrity performance in CO₂ storage sites.     

Geoelectrical methods for monitoring geological CO2 storage: First results from cross-hole and surface–downhole measurements from the CO2SINK test site at Ketzin (Germany)

The feasibility of monitoring CO₂ migration in a saline aquifer at a depth of about 650 m with cross-hole and surface–downhole electrical resistivity tomography (ERT) is investigated at the CO₂SINK test site close to Ketzin (Germany). The permanent vertical electrical resistivity array (VERA) consists of 45 electrodes (15 in the injection well Ktzi201 and 15 in each of the two observation wells Ktzi200 and Ktzi202), successfully placed on the electrically insulated casings, in the depth range of about 590–740 m with a spacing of about 10 m. The three Ketzin wells are arranged as perpendicular triangle with distances of 50 and 100 m.First synthetic modelling studies indicate an increase of the electrical resistivity of about 200% caused by CO₂ injection, corresponding to a bulk CO₂ saturation of 50%, which is in good agreement with laboratory studies. Finite difference inversion of field data delivers three-dimensional resistivity distributions between the wells which are consistent with the reservoir modelling studies.To increase the limited observation area provided by the cross-hole measurements, additional surface–downhole measurements were deployed. A main CO₂ migration in SE–NW direction is deduced from surface to downhole resistivity experiments.The first cross-hole time-lapse results show that the resolution and the coverage of the electrode array in the Ketzin setting are sufficient to resolve the expected resistivity changes on the characteristic length scale of the electrode array. Significant resistivity changes could be measured, however, detailed information on the CO₂ plume could not be resolved yet by VERA under the existing geological circumstances.     

Experimental investigation of wellbore integrity and CO2–brine flow along the casing–cement microannulus

Wellbore integrity is one of the key performance criteria in the geological storage of CO₂. It is significant in any proposed storage site but may be critical to the suitability of depleted oil and gas reservoirs that may have 10’s to 1000’s of abandoned wells. Much previous work has focused on Portland cement which is the primary material used to seal wellbore systems. This work has emphasized the potential dissolution of Portland cement. However, an increasing number of field studies (e.g., Carey et al., 2007), experimental studies (e.g., Kutchko et al., 2006) and theoretical considerations indicate that the most significant leakage mechanism is likely to be flow of CO₂ along the casing–cement microannulus, cement–cement fractures, or the cement–caprock interface.In this study, we investigate the casing–cement microannulus through core-flood experiments. The experiments were conducted on a synthetic wellbore system consisting of a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing that had grooves to accommodate fluid flow. The experiments were conducted at 40 $°$ C and 14 MPa pore pressure for 394 h. During the experiment, 6.2 l of a 50:50 mixture of supercritical CO₂ and 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement–casing wellbore system. Approximately 59,000 pore volumes of fluid moved through the casing–cement grooves. Scanning electron microscopy revealed that the CO₂–brine mixture impacted both the casing and the cement. The Portland cement was carbonated to depths of 50–250 $\mu$m by a diffusion-dominated process. There was very little evidence for mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of mixed calcium and iron carbonate that lined the channels and in one case almost completely filled a channel. The depth of steel corroded was estimated at 25– $30\mu$m and was similar in value to results obtained with a simplified corrosion model.The experimental results were applied to field observations of carbonated wellbore cement by Carey et al. (2007) and Crow et al. (2009) to show that carbonation of the field samples was not accompanied by significant CO₂–brine flow at the casing–cement interface. The sensitivity of standard-grade steel casing to corrosion suggests that relatively straight-forward wireline logging of external casing corrosion could be used as a useful indicator of flow behind casing. These experiments also reinforce other studies that indicate rates of Portland cement deterioration are slow, even in the high-flux CO₂–brine experiments reported here.     

Experimental assessment of brine and/or CO2 leakage through well cements at reservoir conditions

Two sets of experiments on typical Class G well cement were carried out in the laboratory to understand better the potential processes involved in well leakage in the presence of CO₂. In the first set, good-quality cement samples of permeability in the order of 0.1 μD (10^?19 m²) were subjected to 90 days of flow through with CO₂-saturated brine at conditions of pressure, temperature and water salinity characteristic of a typical geological sequestration zone. Cement permeability dropped rapidly at the beginning of the experiment and remained almost constant thereafter, most likely mainly as a result of CO₂ exsolution from the saturated brine due to the pressure drop along the flow path which led to multi-phase flow, relative-permeability effects and the observed reduction in permeability. These processes are identical to those which would occur in the field as well if the cement sheath in the wellbore annulus is of good quality. The second set of experiments, carried out also at in situ conditions and using ethane rather than CO₂ to eliminate any possible geochemical effects, assessed the effect of annular spaces between wellbore casing and cement, and of radial cracks in cement on the effective permeability of the casing-cement assemblage. The results show that, if both the cement and the bond are of good quality, the effective permeability of the assemblage is extremely low (in the order of 1 nD, or 10^?21 m²). The presence of an annular gap and/or cracks in the order of 0.01–0.3 mm in aperture leads to a significant increase in effective permeability, which reaches values in the range of 0.1–1 mD (10^?15 m²). The results of both sets of experiments suggest that good cement and good bonding with casing and the surrounding rock will likely constitute a good and reliable barrier to the upward flow of CO₂ and/or CO₂-saturated brine. The presence of mechanical defects such as gaps in bonding between the casing or the formation, or cracks in the cement annulus itself, leads to flow paths with significant effective permeability. This indicates that the external and internal interfaces of cements in wells would most probably constitute the main flow pathways for fluids leakage in wellbores, including both gaseous/supercritical phase CO₂ and CO₂-saturated brine.     

Coupled hydromechanical modeling of CO2 sequestration in deep saline aquifers

Sequestration of carbon dioxide (CO₂) in deep saline aquifers has emerged as an option for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO₂ that need to be injected into deep saline aquifers may cause large fluid pressure increases. The resulting overpressure may promote reactivation of sealed fractures or the creation of new ones in the caprock seal. This could lead to escape routes for CO₂. In order to assess the probability of such an event, we model an axisymmetric horizontal aquifer–caprock system, including hydromechanical coupling. We study the failure mechanisms, using a viscoplastic approach. Simulations illustrate that, depending on boundary conditions, the least favorable moment takes place at the beginning of injection. Initially, fluid pressure rises sharply because of a reduction in permeability due to desaturation. Once CO₂ fills the pores in the vicinity of the injection well and a capillary fringe is fully developed, the less viscous CO₂ displaces the brine and the capillary fringe laterally. The overpressure caused by the permeability reduction within the capillary fringe due to desaturation decreases with distance from the injection well. This results in a drop in fluid pressure buildup with time, which leads to a safer situation. Nevertheless, in the presence of low-permeability boundaries, fluid pressure continues to rise in the whole aquifer. This occurs when the radius of influence of the injection reaches the outer boundary. Thus, caprock integrity might be compromised in the long term.     

Carbonation of wellbore cement by CO2 diffusion from caprock

To evaluate the risk of corrosion of cement by geosequestered CO₂, samples are being retrieved from wells placed in natural CO₂ deposits [e.g., Crow et al., 2009]. If the cement passing through the cap rock is carbonated, it may indicate that annular gaps or cracks have allowed carbonic acid to come into contact with the cement. However, it must be recognized that the pore water in the cap rock has become saturated with CO₂ over geological time. After the well is placed, the CO₂ will diffuse toward the cement and react with it. A simple analysis of the diffusion kinetics demonstrates that carbonation depths of millimeters to centimeters can be expected from this reaction within the lifetime of a well, in the absence of any cracks or gaps. Therefore, the occurrence of carbonation in cement sealing natural CO₂ deposits must be interpreted with caution.     

Geochemical and solute transport modelling for CO2 storage, what to expect from it?

Geochemistry plays an important role when assessing the impact of CO₂ storage. Due to the potential corrosive character of CO₂, it might affect the chemical and physical properties of the wells, the reservoir and its surroundings and increase the environmental and financial risk of CO₂ storage projects in deep geological structures. An overview of geochemical and solute transport modelling for CO₂ storage purposes is given, its data requirements and gaps are highlighted, and its progress over the last 10 years is discussed. Four different application domains are identified: long-term integrity modelling, injectivity modelling, well integrity modelling and experimental modelling and their current state of the art is discussed. One of the major gaps remaining is the lack of basic thermodynamical and kinetic data at relevant temperature and pressure conditions for each of these four application domains. Real challenges are the coupled solute transport and geomechanical modelling, the modelling of impurities in the CO₂ stream and pore-scale modelling applications.     

Analysis and performance of oil well cement with 30 years of CO2 exposure from the SACROC Unit,West Texas,USA

A core sample including casing, cement, and shale caprock was obtained from a 30-year old CO₂-flooding operation at the SACROC Unit, located in West Texas. The core was investigated as part of a program to evaluate the integrity of Portland-cement based wellbore systems in CO₂-sequestration environments. The recovered cement had air permeabilities in the tenth of a milliDarcy range and thus retained its capacity to prevent significant flow of CO₂. There was evidence, however, for CO₂ migration along both the casing–cement and cement–shale interfaces. A 0.1–0.3 cm thick carbonate precipitate occurs adjacent to the casing. The CO₂ producing this deposit may have traveled up the casing wall or may have infiltrated through the casing threads or points of corrosion. The cement in contact with the shale (0.1–1 cm thick) was heavily carbonated to an assemblage of calcite, aragonite, vaterite, and amorphous alumino-silica residue and was transformed to a distinctive orange color. The CO₂ causing this reaction originated by migration along the cement–shale interface where the presence of shale fragments (filter cake) may have provided a fluid pathway. The integrity of the casing–cement and cement–shale interfaces appears to be the most important issue in the performance of wellbore systems in a CO₂ sequestration reservoir.     

Seismic detection of CO2 leakage along monitoring wellbores

A pilot carbon dioxide (CO₂) sequestration experiment was carried out in the Michigan Basin in which ～10,000 tonnes of supercritical CO₂ was injected into the Bass Island Dolomite (BILD) at 1050 m depth. A passive seismic monitoring (PSM) network was operated before, during and after the ～17-day injection period. The seismic monitoring network consisted of two arrays of eight, three-component sensors, deployed in two monitoring wells at only a few hundred meters from the injection point. 225 microseismic events were detected by the arrays. Of these, only one event was clearly an injection-induced microearthquake. It occurred during injection, approximately 100 m above the BILD formation. No events, down to the magnitude ?3 detection limit, occurred within the BILD formation during the injection. The observed seismic waveforms associated with the other 224 events were quite unusual in that they appear to contain dominantly compressional (P) but no (or extremely weak) shear (S) waves, indicating that they are not associated with shear slip on faults. The microseismic events were unusual in two other ways. First, almost all of the events occurred prior to the start of injection into the BILD formation. Second, hypocenters of the 94 locatable events cluster around the wells where the sensor arrays were deployed, not the injection well. While the temporal evolution of these events shows no correlation with the BILD injection, they do correlate with CO₂ injection for enhanced oil recovery (EOR) into the 1670 m deep Coral Reef formation that had been going on for ～2.5 years prior to the pilot injection experiment into the BILD formation. We conclude that the unusual microseismic events reflect degassing processes associated with leakage up and around the monitoring wells from the EOR-related CO₂ injection into the Coral Reef formation, ～700 m below the depth of the monitoring arrays. This conclusion is also supported by the observation that as soon as injection into the Coral Reef formation resumed at the conclusion of the BILD demonstration experiment, seismic events (essentially identical to the events associated with the Coral Reef injection prior to the BILD experiment) again started to occur close to a monitoring arrays. Taken together, these observations point to vertical migration around the casings of the monitoring wellbores. Detection of these unusual microseismic events was somewhat fortuitous in that the arrays were deployed at the depth where the CO₂ undergoes a strong volume increase during transition from a supercritical state to a gas. Given the large number of pre-existing wellbores that exist in depleted oil and gas reservoirs that might be considered for CO₂ sequestration projects, passive seismic monitoring systems could be deployed at appropriate depths to systematically detect and monitor leakage along them.     

Simultaneous CO2 injection and water production to optimise aquifer storage capacity

The estimates for geological CO₂ storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO₂ that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential.In static capacity estimates, where the maximum stored amount of CO₂ is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO₂ is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO₂. The EU directive on geological CO₂ storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO₂ that can be injected.One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO₂ injection wells. This paper discusses results from simulations of CO₂ injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO₂ shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO₂ over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer.Several design options for the injection operations are investigated: Injection of CO₂ without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed.     

Re-establishment of the proper injectivity of the CO2-injection well Ktzi 201 in Ketzin, Germany

The onshore CO₂-storage site Ketzin consists of one CO₂-injection well and two observation wells. Hydraulic tests revealed permeabilities between 50 and 100 mD for the sandstone rock units. The designated injection well Ktzi 201 showed similar production permeability. After installation of the CO₂-injection string, an injection test with water yielded a significantly lower injectivity of 0.002 m³/d kPa, while the observation wells showed an injection permeability in the same range as the productivity. Several possible reasons for the severe decline in injectivity are discussed. Acidification of the reservoir interval, injection at high wellhead pressure, controlled mini-fractures and back-production of the well are discussed to remove the plugging material to re-establish the required injectivity of the well. It has been decided to perform a nitrogen lift and analyse the back-produced fluids. Initially during the lift, the back-produced fluids were dark-black. Chemical and XRD analyses proved that the black solids consisted mainly of iron sulphide. Sulphate-reducing bacteria (SRB) were detected in fluid samples with up to 10⁶ cells/ml by fluorescent in situ hybridisation (FISH) indicating that the formation of iron sulphide was caused by bacterial activity. Organic compounds within the drilling mud and other technical fluids were likely left during the well completion process, thus providing the energy source for strong proliferation of bacteria. During the lift, the fraction of SRB in the whole bacterial community decreased from approximately 32% in downhole samples to less than 5%. The lift of Ktzi 201 succeeded in the full restoration of the well productivity and injectivity. Additionally, the likely energy source of the SRB was largely removed by the lifting, thus ensuring the long-term preservation of the injectivity.     

Screening and selection of sites for CO2 sequestration based on pressure buildup

This paper presents a simple methodology for estimating pressure pressure buildup due to the injection of supercritical CO₂into a saline formation, and the limiting pressure at which the formation starts to fracture. Pressure buildup is calculated using the approximate solution of Mathias et al. [Mathias, S.A., Hardisty, P.E., Trudell, M.R., Zimmerman, R.W., 2009. Approximate solutions for pressure buildup during CO₂ injection in brine aquifers. Transp. Porous Media. doi:10.1007/s11242-008-9316-7], which accounts for two-phase Forchheimer flow (of supercritical CO₂ and brine) in a compressible porous medium. Compressibility of the rock formation and both fluid phases are also accounted for. Injection pressure is assumed to be limited by the pressure required to fracture the rock formation. Fracture development is assumed to occur when pore pressures exceed the minimum principal stress, which in turn is related to the Poisson’s ratio of the rock formation. Detailed guidance is also offered concerning the estimation of viscosity, density and compressibility for the brine and CO₂. Example calculations are presented in the context of data from the Plains CO₂ Reduction (PCOR) Partnership. Such a methodology will be useful for screening analysis of potential CO₂ injection sites to identify which are worthy of further investigation.     

Coupled reservoir-geomechanical analysis of CO2 injection and ground deformations at In Salah,Algeria

In Salah Gas Project in Algeria has been injecting 0.5–1 million tonnes CO₂ per year over the past 5 years into a water-filled strata at a depth of about 1800–1900 m. Unlike most CO₂ storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20 m. To ensure adequate CO₂ flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1–1.5 km) horizontal injection wells. In an ongoing research project we use field data and coupled reservoir-geomechanical numerical modeling to assess the effectiveness of this approach and to investigate monitoring techniques to evaluate the performance of a CO₂ injection operation in relatively low-permeability formations. Among the field data used are ground surface deformations evaluated from recently acquired satellite-based inferrometry (InSAR). The InSAR data shows a surface uplift on the order of 5 mm per year above active CO₂ injection wells and the uplift pattern extends several km from the injection wells. In this paper we use the observed surface uplift to constrain our coupled reservoir-geomechanical model and conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. The results of our analysis indicate that most of the observed uplift magnitude can be explained by pressure-induced, poro-elastic expansion of the 20-m-thick injection zone, but there could also be a significant contribution from pressure-induced deformations within a 100-m-thick zone of shaly sands immediately above the injection zone.     

Coalbed methane reservoir data and simulator parameter uncertainty modelling for CO2 storage performance assessment

Laboratory studies and a number of field pilots have demonstrated that CO₂ injection into coal seams has the potential to enhance coalbed methane (CBM) recovery with the added advantage that most of the injected CO₂ can be stored permanently in coal. The concept of storing CO₂ in geologic formations as a safe and effective greenhouse gas mitigation option requires public and regulatory acceptance. In this context it is important to develop a good understanding of the reservoir performance, uncertainties and the risks that are associated with geological storage. The paper presented refers to the sources of uncertainty involved in CO₂ storage performance assessment in coalbed methane reservoirs and demonstrates their significance using extensive digital well log data representing the Manville coals in Alberta, Canada. The spatial variability of the reservoir properties was captured through geostatistical analysis, and sequential Gaussian simulations of these provided multiple realisations for the reservoir simulator inputs. A number of CO₂ injection scenarios with variable matrix swelling coefficients were evaluated using a 2D reservoir model and spatially distributed realisations of total net thickness and permeability.     

Assessing the economic feasibility of regional deep saline aquifer CO2 injection and storage: A geomechanics-based workflow applied to the Rose Run sandstone in Eastern Ohio, USA

Typical top-down regional assessments of CO₂ storage feasibility are sufficient for determining the maximum volumetric capacity of deep saline aquifers. However, they do not reflect the regional economic feasibility of storage. This is controlled, in part, by the number and type of injection wells that are necessary to achieve regional CO₂ storage goals. In contrast, the geomechanics-based assessment workflow that we present in this paper follows a bottom-up approach for evaluating regional deep saline aquifer CO₂ storage feasibility. The CO₂ storage capacity of an aquifer is a function of its porous volume as well as its CO₂ injectivity. For a saline aquifer to be considered feasible in this assessment it must be able to store a specified amount of CO₂ at a reasonable cost per ton of CO₂. The proposed assessment workflow has seven steps that include (1) defining the storage project and goals, (2) characterizing the geology and developing a geomechanical model of the aquifer, (3) constructing 3D aquifer models, (4) simulating CO₂ injection, (5,6) evaluating CO₂ injection and storage feasibility (with and without injection well stimulation), and (7) determining whether it is economically feasible to proceed with the storage project. The workflow was applied to a case study of the Rose Run sandstone aquifer in the Eastern Ohio River Valley, USA. We found that it is feasible in this region to inject 113 Mt CO₂/year for 30 years at an associated well cost of less than US $1.31/t CO₂, but only if injectivity enhancement techniques such as hydraulic fracturing and injection induced micro-seismicity are implemented.     

Assessment of basin-scale hydrologic impacts of CO2 sequestration,Illinois basin

Idealized, basin-scale sharp-interface models of CO₂ injection were constructed for the Illinois basin. Porosity and permeability were decreased with depth within the Mount Simon Formation. Eau Claire confining unit porosity and permeability were kept fixed. We used 726 injection wells located near 42 power plants to deliver 80 million metric tons of CO₂/year. After 100 years of continuous injection, deviatoric fluid pressures varied between 5.6 and 18 MPa across central and southern part of the Illinois basin. Maximum deviatoric pressure reached about 50% of lithostatic levels to the south. The pressure disturbance (>0.03 MPa) propagated 10–25 km away from the injection wells resulting in significant well–well pressure interference. These findings are consistent with single-phase analytical solutions of injection. The radial footprint of the CO₂ plume at each well was only 0.5–2 km after 100 years of injection. Net lateral brine displacement was insignificant due to increasing radial distance from injection well and leakage across the Eau Claire confining unit. On geologic time scales CO₂ would migrate northward at a rate of about 6 m/1000 years. Because of paleo-seismic events in this region (M5.5–M7.5), care should be taken to avoid high pore pressures in the southern Illinois basin.     

Geological storage of CO2 in saline aquifers—A review of the experience from existing storage operations

The experience from CO₂ injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO₂ geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO₂ plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO₂ had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO₂/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.     

CO2 emissions from Polish cement industry

The cement industry is one of the most significant sources of anthropogenic emissions of CO₂. It is connected with the specific character of the production processes, during which great quantities of CO₂ are produced. Basic actions to reduce CO₂ emissions recommended by the European Union's, Reference Document on Best Available Techniques in the Cement and Lime Manufacturing Industries, include: reduction of fuel consumption, selection of raw materials with low content of organic compounds and fuels with low coal contribution to heating value. All actions connected with the improvement of energy conversion efficiency of the cement production process cause CO₂ emissions reduction. The use of at most acceptable by the valid standards amounts of waste as raw materials and additives for cement production, also brings about the reduction of significant part of CO₂ emissions. These measures have been and continue to be pursued by the cement factories in Poland. This article describes the evolution of the cement industry in Poland over the period 1998–2008 and the resulting changes in CO₂ emissions and explores the drivers for these changes. The sources of CO₂ emissions in cement industry have been presented in this article as well as a discussion of potential ways to reduce Polish cement industry emissions even further.     

Evaluation of large-scale CO2 storage on fresh-water sections of aquifers: An example from the Texas Gulf Coast Basin

Large-scale injections of CO₂ into subsurface saline aquifers have been proposed to remediate climate change related to buildup of green house gases in the atmosphere. The pressure buildup caused by such injections may impact a volume of the basin significantly larger than the CO₂ plume itself. In areas with hydrological settings similar to the Gulf Coast Basin, the perturbation of the flow-field in deep parts of the basin could result in brines or brackish water being pushed up-dip into unconfined sections of the same formations or into the capture zone of fresh-water wells. The premise of the current study is that the details of multiple-phase flow processes necessary to model the near field evolution of the CO₂ plume are not necessary to describe the impact of the pressure anomaly on up-dip aquifers. This paper quantitatively explores conditions under which shallow groundwater would be impacted by up-dip displacement of brines, utilizing an existing carefully calibrated flow model. Modeling an injection of water, arguably equivalent to 50 million tons of CO₂/year for 50 years resulted in an average water-table rise of 1 m, with minor increase in stream baseflow and larger increase in ground water evapotranspiration, but no significant change in salinity.