Search

• The topic of waste heat was mentioned in this report, as it represents an important learning. Waste heat issue and audit finding will be addressed in a subsequent publication. To provide clarity to the reader with regards to what data/information was used to write this manuscript, the title of manuscript was revised to "Quest Carbon Capture and Storage Offset Project: findings and learnings from 1 st reporting period". • Replaced "Shell is submitting the serialization packages for Quest to the Offset Registry without a claim for waste heat at this time." with "Shell submitted the serialization packages for Quest to the Offset Registry without a claim for waste heat until the waste heat calculation methodology is approved.". • Within Section 4.2.1 , an example of findings from an audit, namely injection gas compositional data, is discussed. Significant revisions to Section 4.2.1 to address these questions. • The quantification methodology of the emission reduction associated with the Quest project is based on the difference between the mass of CO 2 stored and the sum of CO 2 emissions attributed to project activities (e.g. emissions due to construction and well drilling). The following equations are used to quantify the emission reductions resulting from the Quest carbon capture and storage activities by comparing baseline and project conditions. • Added following footnote to Table 1 : ^ Note that the pipeline design was a 12-inch CO2 pipeline as per CSA Z662 transporting the dehydrated, compressed, and dense-phase CO2 from the capture facility to the injection wells. This should minimize the risk of failure in the transportation of CO2. • Replaced conformance with 'conformance *' and added following footnote: * Ensure Conformance refers to indicating the long-term effectiveness of CO 2 storage by demonstrating actual storage performance is consistent with expectations about injectivity, capacity, and CO 2 behaviour inside the storage complex. • Added following text "Invoices of materials supplied were used to determine the nature and quantity of each material used in the capture process. This information was then used to estimate CO2 emissions per year based on an emissions factor for a specific material". • Added following sentence after "...flow meters and on-line analyzers.": "The project has an online gas analyzer to determine the CO 2 concentration in the injection gas stream. The analyzer is located in a building just before the CO 2 enters the ˜65 km underground pipeline which transports the CO 2 from the capture facility to the injection well pads". • "The key regulatory mandate is the materiality threshold for the absolute value of all errors found by auditors must be less than 2% of the total GHG Assertion for an Offset Project for a specified reporting period. As a result, the onsite lab and third-party lab provide supporting evidence that the ambient pressure compensated CO2 concentration data from the online analyzer are accurate". Quest is a fully integrated Carbon Capture and Storage (CCS) project that started CO 2 injection in August of 2015. The Quest CCS Project is located near Fort Saskatchewan, Alberta, Canada. It includes a capture facility which uses a Shell amine technology, a pipeline of about 65 km length, and three injection well pads. Each injection well pad has an injection well, a deep monitoring well, and shallow groundwater wells. The storage complex is geologically defined by the injection reservoir, a deep saline aquifer called the Basal Cambrian Sand (BCS) (about 45 m thick) and several seals, including the Middle Cambrian Shale (about 50 m thick) and Lotsberg Salts (about 120 m thick). As of August 2018, over three million tonnes of CO 2 have been safely injected and permanently stored in the BCS. The Alberta Carbon Competitiveness Incentive Regulation (CCIR) requires the use of standard methods of quantification for reporting greenhouse gas (GHG) emissions for facilities with over 100,000 tonnes of carbon dioxide equivalent (CO 2 e) per year. An emission offset project is required to comply with CCIR, associated standards and protocols, to demonstrate a reduction in the specified gas emissions and, in the case of Quest, geological sequestration. Quest is the first CCS project to implement an offset project in the context of commercial scale on-shore CO 2 geological sequestration within a saline aquifer. Quest uses the Quantification Protocol for CO 2 Capture and Permanent Storage in Deep Saline Aquifers, from Alberta Environment and Parks. An offset project must develop an offset project plan (OPP) which demonstrates how the project meets the requirement of the protocol, describes how GHG emissions reductions are achieved, identifies risks associated with the quantification of emission reduction benefits, and describes methodologies used to quantify sources and sinks. Subsequent to completing the OPP, an offset project will put together offset project reports (OPR) to report on the net reductions of GHG emissions for a specific period. The intent of this paper is a) to provide an overview of the OPP and OPR for the Quest CCS project, and b) to discuss learnings from the initial compilation and submission of offset project reports. The key learning at this time is associated to the equipment improvements to the injection gas online analyzer. [ABSTRACT FROM AUTHOR]

Highlights • Multi-tracer approach used to definitively assess soil gas migration issues. • CO 2 injection reservoir leak alleged due to CO 2 concentrations in soils. • δ13C CO2 and δ18O CO2 values provided limited insight. • 14C CO2 indicated 'modern carbon' supporting a microbial source for soil gases. Abstract Stable (13C) and radiogenic (14C) carbon isotope tracers are recognized approaches to identify gas sources using soil gas monitoring techniques; however, definitive characterization from a subsurface injection/storage reservoir can be complicated by processes that produce and consume CO 2. Few studies assess the combined use of compositional (fixed gases, hydrocarbons, and sulphurous compounds) and isotopic (13C, 18O and 14C) indicators from soil gases as tools to evaluate CO 2 storage reservoir leaks. Compositional and isotopic indicators from soil gases were compared at an investigation site (IS) alleged to be impacted by CO 2 leaking from an underlying injection reservoir with a baseline control site (BCS) outside of the injection area. Soil gas δ 13C CO2 values collected from the IS (−23.4‰to −22.6‰) were comparable with the range observed at the BCS (−22.8‰ and −23.3‰), falling within the range anticipated for both biogenic and injected CO 2. 14C values were also comparable between IS (98.0 pMC to 107.0 pMC) and BCS (102.8 pMC to 105.3 pMC) sites, representing a modern carbon source that was distinct from the CO 2 injection gas (0.34 pMC). The results provide several lines of evidence that CO 2 fluxes in soil gases at the IS were related to naturally occurring processes and were not caused by a gas migration issue from a geological CO 2 storage reservoir. [ABSTRACT FROM AUTHOR]

Highlights • Greenhouse gas emissions of oil produced by CO 2 enhanced recovery are quantified. • CO 2 used for the study was captured from a natural gas-processing plant. • Compared to the conventional approach, the use of CO 2 produced lower GHG emissions. Abstract This life cycle analysis (LCA) evaluates life cycle greenhouse gas (GHG) emissions associated with a system that produces both natural gas and crude oil. Two systems are defined: System 1, which independently produces natural gas and oil, and System 2, which captures carbon dioxide (CO 2) from the natural gas-processing plant and utilizes this captured CO 2 for enhanced oil recovery (EOR). The LCA uses customized spreadsheet models with emission factors from peer-reviewed literature and publications of the National Energy Technology Laboratory of the U.S. Department of Energy. The modeling results show that the CO 2 EOR scenario using captured CO 2 produces both natural gas and oil with lower life cycle GHG emissions than alternative systems producing natural gas and oil independently. Sensitivity analyses show that the model results are most sensitive to the fraction of CO 2 captured (or equivalently, the fraction of CO 2 vented) at the natural gas-processing facility and the incremental oil recovery factor and net CO 2 utilization factor of the EOR operations. The input variable driving the relative difference in life cycle GHG emissions between these two systems is the fraction of CO 2 captured at the natural gas-processing facility (i.e., the capture rate). The results of this study highlight the necessity of linking processes in the life cycle modeling, as a change to one process can affect other processes within the coupled energy system comprised of natural gas and oil. In addition, this analysis shows, as prior work has also suggested, that CO 2 EOR using captured anthropogenic CO 2 provides a viable means for offsetting carbon emissions from oil production and combustion via the associated storage of CO 2 that occurs incidentally during this tertiary method of oil recovery. [ABSTRACT FROM AUTHOR]

Highlights • Foam significantly increase capillary trapping of CO 2 in saline aquifer. • A foam stabilizing agent is needed to prevent mobilization of trapped CO 2. • Electrical resistivity tool monitors capillary trapping and stability of CO 2 in-situ. • A method to monitor and measure foam stability and foam decay rate in porous media. • A method to screen foam stabilizers for foam-assisted CO 2 storage in saline aquifers. Abstract Capillary trapping is one of the quickest mechanism by which carbon dioxide (CO 2) is trapped during geological sequestration. It is also of the most immediate importance because a significant fraction of the injected CO 2 can be stored and rendered immobile in the event of a leak. Many research papers have been published in the past decade focusing on improving capillary trapping of CO 2 during geological sequestration. In this study, a different approach was investigated, which involved the use of colloidal materials to enhance capillary trapping of CO 2 during sequestration in saline aquifers. A suite of reservoir condition laboratory experiments was conducted on some selected reservoir rock samples saturated with synthetic brine to mimic actual saline aquifers. A foaming agent (0.025% wt. nonionic surfactant) was dissolved in the brine. Foams were then generated in the rock samples by alternate injection of gas and brine using a coreflooding setup. An electrical resistivity measuring tool attached to the setup was used for real-time and in-situ tracking of pore-scale events such as gas movement, capillary trapping of gas, and the stability of the trapped gas. Both Nitrogen (N 2) and CO 2 gases were investigated and the results showed a tremendous increase in the amount of trapped N 2 and CO 2 gases when foams were applied compared to gas injection without foams. However, low interfacial tension between CO 2 and the surfactant solution affected the viability of foams in trapping CO 2. Nevertheless, the use of CO 2 foam stabilizers is promising in addressing this challenge. The methodology described in this paper can be used to test the efficiency of a variety of CO 2 foam stabilizing agents that may be developed. [ABSTRACT FROM AUTHOR]

Graphical abstract Highlights • Experimental ATAP facility for SCCO2 injection in brine saturated sandstone. • Relative permeability test studying wettability and capillary trapping in drainage. • The akin of sandstone to SCCO2 is unfavorable for the capillary trap mechanism. • Lower residual saturation of SCCO2 after the imbibition process. Abstract The capture and storage of CO2 represent a technologically viable option to reduce greenhouse gas emissions from the use of fossil fuels. The petrophysical characteristics of the storage, the type of rock, the state of the gas and the conditions of the injection process affect the development of the residual trap mechanism. In the ATAP experimental facility, supercritical CO2 was injected following two methodologies, the steady and unsteady states into three sandstone samples with different porosities and permeabilities in a triaxial cell, which reproduces a rock-brine system. The results were obtained and interpreted based on numerical adjustment models, which were made with the Cydar™ software in the first drainage process. The results indicate the alteration of the storage wettability, which suggests a greater affinity of the rock to SCCO2. The relative permeability curves obtained by history matching and successive iterations were analyzed with Craig's rule and compared with the SCAL (Special Core Analysis) measurements. The SCCO2 injection increases the storage capacity because of its higher density, and the reservoir rock shows more affinity to CO2 in this phase. Nevertheless, during the imbibition process, the amount of CO2 retained by capillary trapping is lower than that in a more water-wet storage. [ABSTRACT FROM AUTHOR]

An enhanced oil recovery (EOR) technique comprising the alternate injection of gas (CO 2 ) and water, commonly referred to as water alternating gas (WAG) flooding, is currently ongoing at an oil field in the northeastern Powder River Basin (PRB), where 4 million barrels (MMbbl) of oil were produced between May 2013 and September 2017. During WAG flooding, a large amount of CO 2 , which contains some impurities, is produced at the surface with the recovered oil and reinjected into the reservoir to minimize the amount of purchased CO 2 . The concentration of these impurities in the CO 2 , which are dominated by CH 4 , is a key parameter in the design of miscible CO 2 flooding of an oil reservoir and in the quantitative assessment of the associated storage of CO 2 that occurs in the reservoir. For a given oil and reservoir temperature, the CO 2 –oil minimum miscibility pressure (MMP) is strongly and adversely affected by the presence of CH 4 , the concentration of which varies with time and operational conditions, such as injection pressure, flooding pattern, and injection scheme (i.e., continuous CO 2 injection or WAG). To capture the full range of potential variation in the MMP caused by the presence of CH 4 , a series of laboratory experiments were conducted to determine CO 2 –oil MMP with different mole percentages of CH 4 in the CO 2 . All of the experiments were performed at reservoir temperature (108 °F) using the VIT (vanishing interfacial tension) method. Results showed that MMP increases from 1403 to 4085 psi as the mole percentage of CH 4 in the CO 2 increases from 0% to 100%. To assess the impact of this variation in MMP on the oil recovery performance in the field, a history-matched, compositional reservoir simulation model was used to predict the oil production performance for a WAG flood using CO 2 that contained a range of CH 4 concentrations. The reservoir simulations examined the effects of permeability heterogeneity, fluid crossflow, and phase behavior on the oil displacement performance in three-dimensional space over time. Simulation results indicated that CO 2 floods using a limited range of CO 2 –CH 4 mixtures could still maintain multiple-contact miscibility and result in effective EOR. In addition, the ability to reinject produced CO 2 –CH 4 mixtures as is, without removal of the CH 4 , ensured that this approach to EOR would continue to be cost-effective. [ABSTRACT FROM AUTHOR]

CO 2 injection and storage in geological reservoirs is an attractive prospect for mitigating the anthropogenic production of greenhouse gases and global warming. The technology could lead to mineral precipitation and therefore stable storage over geological time scales. This contribution investigates the evolution of three calcite-rich reservoir rock analogues during injection of and exposure to supercritical CO 2 (scCO 2 ), i.e., two limestones (Tuffeau and Savonnieres) and a synthetic calcite-cemented sandstone (CIPS). Three types of exposure protocols have been conducted: (i) scCO 2 injection and a four-hour residence time in an initially dry rock; (ii) scCO 2 injection and a two-hour residence time in an initially brine-saturated rock; and (iii) scCO 2 injection and a four-hour residence time in an initially brine-saturated rock. Two aspects are monitored during these experiments: (i) the evolution of the pore fluid chemical composition; and (ii) the evolution of the rocks’ physical properties (i.e. porosity, permeability, P-wave velocity and electrical resistivity). Additionally, some scCO 2 injection and exposure experiments in the brine-saturated rocks have been conducted using X-ray tomographic monitoring. X-ray tomographic monitoring suggests that scCO 2 first displaces the water, leading to an average water saturation of about 70–90%. Then, scCO 2 dissolves in the pore brine, leading to a homogeneous decrease by about 3% in water saturation of the sample. As a result, the pore brine acidifies even after 2 h of exposure only, which leads to calcite dissolution and a significant increase in the brine’s concentration in calcium cations. For the samples and most exposure experiments, evidence of calcite dissolution is inferred from the measured physical properties. For the brine-saturated Tuffeau limestone and CIPS sandstone, calcite dissolution leads to significant mechanical weakening. For the brine-saturated Savonnieres limestone, the sample subject to two-hour residence time shows evidence of calcite dissolution, whereas the sample after four-hour residence time does not. Calcite re-precipitation could be the cause of this unexpected response after four hours. [ABSTRACT FROM AUTHOR]

• A typical five-spot gas reservoir model is modified to analyze CO 2 -EGR and CO 2 storage. • CO 2 -brine-rock interactions are considered in the process of CO 2 flooding. • The presence of irreducible water makes CO 2 displacement better. • The presence of irreducible water makes CO 2 long-term storage safer. CO 2 flooding to enhance gas recovery (CO 2 -EGR) with CO 2 storage offers the prospects of significant environmental and economic benefits by increasing CH 4 recovery while simultaneously storing CO 2. Most studies ignored the interaction of water with CO 2 and the formation rocks and the influence of irreducible water to enhance CH 4 recovery combined with CO 2 storage were poorly understood by core-flooding experiments. In this research, a numerical model of a five-spot well pattern was developed by benchmarking against the existing literature, and the model was further modified to investigate the effects of irreducible water on CO 2 -EGR and CO 2 storage in gas reservoirs. The injected CO 2 preferentially moved horizontally and gradually flowed vertically to flood CH 4 , making the displacement front an inclined CO 2 -CH 4 mixing zone. The model with irreducible water changed from 0% to 40%, the CO 2 sweep efficiency improved and the CH 4 recovery increased by 4.37%. This could be attributed to the narrowing of the CO 2 -CH 4 mixing zone and the change in displacement front from an inclined horizontal plane to a near arc plane with better stability. The cumulatively stored CO 2 decreased by 21.24%, due to the early CO 2 breakthrough and shut-in times. However, because more CO 2 was dissolved in water and trapped in residual gas, the contribution of CO 2 solubility trapping and CO 2 residual trapping increased by 12.01% and 10.34% respectively, while CO 2 structural trapping decreased by 22.86%, resulting in a significant increase in long-term storage security. Mineral reactions had a negligible influence on CO 2 -EGR and CO 2 sequestration in the CO 2 flooding process. The higher the salinity, the lower the amount of dissolved CO 2 , and the lower the CH 4 recovery and cumulatively stored CO 2 , with decreased security of CO 2 storage with limited impact. The higher the irreducible water saturation (S wi), the more CO 2 dissolved, and the CH 4 recovery and long-term storage security of CO 2 improved with a reduction of cumulatively stored CO 2. Changing the gas relative permeability (K rg) has a small effect for CH 4 recovery and CO 2 storage. This research may provide new insights into analyzing the mechanism of irreducible water on the influence of CO 2 -EGR and CO 2 storage, laying a foundation for the optimization of CO 2 -EGR schemes and the implementation of field applications in water-bearing gas reservoirs with CO 2 injection in the future. [ABSTRACT FROM AUTHOR]

Successful operation of CO 2 storage projects requires careful management of injection pressure to ensure that the integrity of the cap rock and other containment units is not compromised by mechanical failure. Injection of CO 2 will lead to some increase in the pore pressure of the target storage formation and the project design will include some expected range of acceptable pressure variations required to achieve sufficient injectivity and to avoid loss of formation integrity. Accurate determination of the formation fracture pressures is a key factor controlling the maximum allowable injection pressure during operations. In this study we review the three main approaches for determining fracture pressure: (a) theoretical methods, (b) use of formation well-test data and (c) analysis of injection data during injection. While theoretical methods are valuable for early planning of projects, predictions based on formation well-test data are generally used immediately prior to and during injection operations. Using example site data, we show how careful analysis of wellhead pressure and rate data during injection operations may be used to optimize the injection plan using the actual in situ conditions in the rock formation around the injection well and for the specific properties of the injection fluid. Using injection pressure time-series datasets over an extended period of time allows improved accuracy in the estimation of the fracture pressure limits and an appreciation of their variation over a larger volume of the formation than can be estimated from well tests. [ABSTRACT FROM AUTHOR]

Enhanced oil recovery (EOR) by the injection of CO 2 into the oil reservoir is widely practiced for stimulating oil production, which is also favorable for CCS (carbon capture and storage) due to the effect of sequestrating CO 2 into the empty space of the reservoir along with oil production. Although economic and environmental benefits can be obtained through CO 2 EOR, it requires considerable capital investment and expenditure for the operation. Therefore, it is helpful to assess systematically the life-time effect of CO 2 EOR by evaluating the capital and energy flow. Rather considering collectively overall mass flows of CO 2 purchase, recycling, sequestration and oil production throughout the whole life-cycle, this study presents the assessment of CO 2 EOR in a multi-period manner in which CO 2 supply is systematically scheduled, subject to the availability of external CO 2 sources and time-dependent relationship between CO 2 injection, CO 2 supply and CO 2 recycle. The methodological procedure for the proposed economical assessment is presented with the case study, in which CO 2 supply schedule is optimized to maximize net present value (NPV), considering the constraints imposed by time-dependent availability of CO 2 supply sources. Sensitivity analysis of key design parameters is performed to gain conceptual insights for the design and operation of CO 2 EOR. [ABSTRACT FROM AUTHOR]

A unified model considering heat source/sink effects is developed to investigate flow and thermal behavior of pure CO 2 injection for sequestration, EOR, and fracturing. The model is based on mass conservation, momentum, and energy balance and employs a state-of-the-art equation of state and transport models of CO 2 to calculate in-situ thermodynamic and transport properties, respectively for a certain section of wellbore. Temperature, pressure, and properties of CO 2 are coupled in the depth direction using an iteration scheme. CO 2 , the annular fluid, and formation are coupled to calculate the overall heat transfer coefficient in the radial direction. The model is validated using data from both field and numerical simulation. Heat transfer mechanism involving thermal resistance and heat source/sink in wellbore is analyzed. A sensitivity study is also conducted to investigate the influence of factors on bottomhole pressure and temperature. Results indicate that annular fluid is the most important thermal resistance in the wellbore. The natural convection of liquid in annulus is much stronger than that of gas, which can greatly promote heat transfer. The heat source/sink effects consist of gas expansion, frictional heat, and Joule–Thomson effect. Their contributions to wellbore heat transfer vary intensely with mass flow rate or Reynolds number. Wellbore heat transfer is dominated by the formation at low flow rates, in which the equilibrium state can be attained at shallow depths. Both bottomhole pressure and temperature change linearly with injection pressure and temperature; there is a non-linear relationship between bottomhole pressure/temperature and time. [ABSTRACT FROM AUTHOR]

We present the results of core-flooding experiments by assessing the impact of capillary heterogeneity on residual and dissolution CO 2 trapping. Two types of injection tests with different rates are conducted: single-phase (supercritical CO 2 ) injection and co-injection (equilibrated CO 2 and brine) cases are considered for drainage tests. In case of the single-phase injection, CO 2 builds up at a low capillary pressure ( P c ) zone located upstream of a high P c zone as CO 2 was hindered to transport across the barriers. The experiments were conducted under capillary-dominated condition, and as capillary number ( N c ) was increased with greater injection rate, the increased viscous force led higher CO 2 saturation in fine matrix implying that high P c zone was more sensitive to the injection rate than the low P c zone. The co-injection, however, leads to greater CO 2 saturation at the high P c zone. The observed disparity of CO 2 saturation patterns in these two experiments resulted from the induced pressure gradient across the core as well as the greater capillary forces in high P c zone. The following imbibition test, which was designed to reproduce conditions for the post-injection period, characterized three regimes of spatio-temporal variation of trapping mechanisms as follows: (1) displacement of mobile CO 2 by the injected brine and concurrent CO 2 dissolution into the fresh brine; (2) preservation of immobile CO 2 as a residual trapping; and (3) gradual CO 2 dissolution into the fresh brine. [ABSTRACT FROM AUTHOR]

The injection of CO 2 into a depleted reservoir will alter the pore pressure, which if sufficiently perturbed could result in fault reactivation. This paper presents an experimental study of fault reactivation potential in fully saturated kaolinite and Ball Clay fault gouges. Clear differences were observed in fault reactivation pressure when water was injected, with the addition of mica/illite in Ball Clay seen to reduce the pressure necessary for reactivation. Slip occurred once pore-pressure within the gouge was sufficient to overcome the normal stress acting on the fault. During gas injection localised dilatant pathways are formed with approximately only 15% of the fault observing an elevated gas pressure. This localisation is insufficient to overcome normal stress and so reactivation is not initiated. Therefore faults are more likely to conduct gas than to reactivate. The Mohr approach of assessing fault reactivity potential gave mixed results. Hydro-mechanical coupling, saturation state, mineralogical composition and time-dependent features of the clay require inclusion in this approach otherwise experiments that are predicted to be stable result in fault reactivation. [ABSTRACT FROM AUTHOR]

• Injecting flue gas captured after oxy-combustion in depleted tight hydrocarbon reservoir can lead to the oxidation of the residual hydrocarbons. • The temperature increase due to the oxidation exothermicity depends strongly on the heat capacity of the rocks. • A high heat capacity makes the temperature increase negligible. • Thermal conductivity and its potential anisotropy have almost no impact on temperature profile. CO 2 storage in depleted tight hydrocarbon reservoir seems to be a promising solution to mitigate greenhouse gas emissions. However, flue gas contains not only CO 2 but also minor gaseous impurities due to CO 2 production or capture processes. In the case of oxy-combustion, the main impurity can be O 2 in concentration up to 7%. O 2 injection into the reservoir can lead to the oxidation of the residual hydrocarbons and therefore, it is necessary to assess the thermal consequences on the reservoir. COMSOL Multiphysics® has been used to model an axisymmetric fractured porous reservoir with its cap and base rocks and containing n- octane as a model compound of residual oil. A global kinetic model for n- octane oxidation has been derived from a previous detailed free-radical model, and implemented into the reservoir model. Simulated injections of N 2 /O 2 mixture (representing a simplified flue gas) have been performed to compute temperature, pressure and n- octane concentration profiles. The results show that the oxidation exothermicity may have a strong influence on temperature profile, especially when the heat capacity of the rock is rather low. In these conditions, the remaining hydrocarbons may be consumed in some months. However, the influence of the thermal conductivity seems negligible. Therefore, it appears safer to select reservoirs whose rocks compositions, in particular the cap and base rocks, have a high heat capacity to promote heat dissipation. It is a criterion to consider when selecting a storage site containing residual hydrocarbons, especially for CO 2 captured after oxy-combustion. [ABSTRACT FROM AUTHOR]

Drying and salt precipitation in geological formations can have serious consequences for upstream operations in terms of injectivity and productivity. Here we investigate the consequences of supercritical CO 2 injection in sandstones. The reported findings are directly relevant for CO 2 sequestration and acid–gas injection operations, but might also be of interest to a broader community dealing with drying and capillary phenomena. By injecting dry supercritical CO 2 into brine-saturated sandstone, we investigate the drying process and the associated precipitation of salts in a capillary-pressure-dominated flow regime. Precipitation patterns were recorded during the drying process by means of μCT scanning. The experimental results and numerical simulations show that under a critical flow rate salt precipitates with an inhomogeneous spatial distribution because of brine and solutes being transported in counter-current flow upstream where salt eventually precipitates. A substantial impairment of the absolute permeability has been found, but despite high local salt accumulation, the effective CO 2 permeability increased during all experiments. This phenomenon is a result of the observed microscopic precipitation pattern and eventually the resulting K ( ϕ ) relationship. The findings in this paper are related to unimodal sandstone. In a companion paper ( Ott et al., 2014 ) we present data on the distinctly different consequences of salt precipitation in dual- or multi-porosity rocks. [ABSTRACT FROM AUTHOR]

Large-scale pressure increases resulting from carbon dioxide (CO 2 ) injection in the subsurface can potentially impact caprock integrity, induce reactivation of critically stressed faults, and drive CO 2 or brine through conductive features into shallow groundwater. Pressure management involving the extraction of native fluids from storage formations can be used to reduce such pressure increases. However, dealing with large volumes of extracted brine can be technically challenging and expensive. Selection of optimal well locations and pumping rates are critical for maximizing CO 2 storage and minimizing brine extraction during geologic CO 2 sequestration (GCS). Robust and efficient computerized algorithms combining reservoir models and optimization methods are needed to make proper decisions on well placement and pumping rates. This study presents a constrained differential evolution (CDE) algorithm for solving global optimization problems involving pressure management of GCS projects. Application of the CDE optimization methodology was demonstrated for a hypothetical CO 2 storage scenario in a deep sandstone reservoir in the Southern San Joaquin Basin in California, USA. Industrial-scale storage of CO 2 would generate significant pressure buildup in this formation, which in turn would raise concerns about induced seismicity due to presence of multiple faults surrounding the injection site. Through the CDE optimization algorithm coupled to a vertically-averaged reservoir simulator, we successfully estimated optimal solutions for brine extraction wells in the reservoir that would limit the local pressure along the faults to a prescribed threshold. Multiple realizations of the reservoir permeability field were created to understand the impact of reservoir heterogeneity on optimization results. Our results indicate that the reservoir slope and heterogeneity have significant impact on optimum extraction rates. Reservoir heterogeneity is also a significant factor for extraction well locations, suggesting that in practice decisions about extraction well placement through optimization should be made at later project stages when data from a few years of CO 2 injection have allowed iterative updating and refining of the reservoir forward models. Although the study focused on optimization of brine extraction, the CDE optimization methodology presented in this paper has also potential to solve other complex optimization problems related to GCS, such as increasing storage efficiency by enhancing injectivity and capillary and dissolution trapping. [ABSTRACT FROM AUTHOR]

A solution to the increasing greenhouse gas emissions is carbon capture and storage. At the Sleipner field, offshore Norway, carbon dioxide is separated from the produced gas and injected into the Utsira formation at approximately 1000 m depth. The Utsira formation is a high porosity saline aquifer that is 200–300 m thick in the injection area. In 1994, two years before the injection started, a seismic survey was acquired. The survey has been followed up by several seismic surveys acquired to monitor the migration of the injected gas. The full waveform inversion (FWI) method is a non-linear inverse method for estimating subsurface elastic parameters. Time-lapse FWI has recently been suggested as a monitoring tool for resolving time-lapse changes directly in the elastic parameter models. This paper presents an application of a three dimensional implementation of isotropic elastic time-lapse FWI applied on time-lapse field data from the Sleipner area. The baseline dataset is the 1994 dataset, whereas the monitor dataset is the survey acquired in 2006 after ten years of injection. Time-lapse FWI is used to estimate separate elastic parameter models for both the baseline and the monitor datasets. The results show that FWI is able to estimate detailed elastic parameter models that produce synthetic data that match the field data. The inverted models are used in a pre-stack depth migration method to yield detailed seismic images of the Sleipner before and after the injection of the gas. The gas cloud after ten years of injection is clearly visible on the monitor seismic images. The baseline and monitor seismic images show events and discontinuities that can explain the migration pathways of the injected gas through the Utsira formation. [ABSTRACT FROM AUTHOR]

Three-dimensional (3D) crosshole electrical resistivity tomography (ERT) was used to monitor a pilot CO 2 injection experiment at Vrøgum, western Denmark. The purpose was to evaluate the effectiveness of the ERT method for detection of small electrical conductivity (EC) changes during the first 2 days of CO 2 injection in a shallow siliciclastic aquifer and to study the early-time behavior of a controlled small gaseous CO 2 release. 45 kg of CO 2 was injected over a 50-h period at 9.85 m depth. ERT data were collected using horizontal bipole-bipole (HBB) and vertical bipole-bipole (VBB) arrays. The combined HBB and VBB data sets were inverted using a difference inversion algorithm for cancellation of coherent noises and enhanced resolution of small changes. ERT detected the small bulk EC changes (<10%) from conductive dissolved CO 2 and resistive gaseous CO 2 . The primary factors that control the migration of a CO 2 plume consist of buoyancy of gaseous CO 2 , local heterogeneity, groundwater flow and external pressure exerted by the injector. The CO 2 plume at the Vrøgum site migrated mostly upward due to buoyancy and it also skewed toward northeastern region by overcoming local groundwater flow. The conductive eastern part is more porous and becomes the preferential pathway for the CO 2 plume, which was trapped within the slightly more porous glacial sand layer between 5 m and 10 m depths. The gaseous and dissolved CO 2 plumes are collocated and grow in tandem for the first 24 h and their opposite effects resulted in a small bulk EC increase. After raising the injection rate from 10 g/min to 20 g/min at the 24-h mark, the CO 2 plume grew quickly. The bulk EC changes from ERT agreed partially with water sample EC and GPR data. The apparent disagreement between high CO 2 gas saturation and prevailing positive bulk EC changes may be caused by limited and variable ERT resolution, low ERT sensitivity to resistive anomalies and uncalibrated CO 2 gas saturation. ERT data show a broader CO 2 plume while water sample EC had higher fine-scale variability. Our ERT electrode configuration can be optimized for more efficient data acquisition and better spatial resolution. [ABSTRACT FROM AUTHOR]

A reliable carbon dioxide (CO 2 ) storage resource estimation method is crucial if carbon capture and storage in deep saline formations (DSFs) is to gain widespread deployment for reducing anthropogenic CO 2 emissions to the atmosphere. Most of the published methodologies are based on a volumetric calculation and do not consider the effect of site-specific dynamic factors (e.g., injection rate, pressure interference). Several studies suggest these dynamic components may play the dominant role in storing CO 2 in DSFs. In this study, CO 2 storage resource estimates and efficiencies for two deep saline systems were calculated using volumetric and dynamic methodologies. Comparison of the results indicates that dynamic CO 2 storage efficiency is time-dependent. For short injection lengths (∼50 years), an open system has an efficiency similar to a closed system, and volumetric storage resource estimates are too high. For long injection time frames (∼2000 years), the dynamic storage resource of open systems approaches the volumetric potential. These results suggest that volumetric assessments are reliable provided it is understood that it may take hundreds of wells and/or injection for hundreds of years to reach a formation's effective CO 2 storage resource potential. Additionally, operational factors such as water extraction can increase CO 2 storage resource and efficiency. [ABSTRACT FROM AUTHOR]

CO 2 injection in saline aquifers is one solution to avoid the emission of this greenhouse gas to the atmosphere. This process induces a pore-pressure build-up around the borehole that generates tensile and shear micro-earthquakes which emit P and S waves if given pressure thresholds are exceeded. Here, we develop a simple model to simulate micro-seismicity in a layer saturated with brine, based on an analytical solution of pressure diffusion and an emission criterion for P and S waves. The model is based on poroelasticity and allows us to obtain estimations of the hydraulic diffusivity on the basis of the location of the micro-earthquakes (defining the CO 2 plume) and the triggering time. Wave propagation of P and S waves is simulated with a full-wave solver, where each emission point is a source proportional to the difference of the pore pressure and the tensile and shear pressure thresholds. Finally a reverse-time migration algorithm is outlined to locate the asynchronous sources induced by the fluid flow, determinated by the maximum amplitude at each cell versus the back propagation time. [ABSTRACT FROM AUTHOR]

CO 2 capture and storage (CCS) is recognized as a promising solution to tackle greenhouse gas emissions. Key issues associated with CCS relate to the integrity of the reservoir and the containment effectiveness. Some risk events (e.g. regional over-pressurization, leakage through a fault or an abandoned well) identified in the risk analysis may be linked with surface deformations anomalies, which can be detected and followed using surface deformation measurements. At In-Salah (Algeria), Interferometric Synthetic Aperture Radar (InSAR) data are available for all points due to ideal surface conditions. If a similar injection occurred in constrained conditions (large cover of vegetated areas for instance), a geodetic network (set of corner reflectors that constitute artificial measurements points) could be used to compensate the scarcity of existing persistent scatterers. The present study aims at exploring the feasibility of using such a geodetic network as part of the monitoring plan in constrained conditions. The sizing of such a network is discussed regarding three monitoring objectives: regional-scale surveillance, local anomaly with known and unknown spatial locations. In the context of In-Salah, a very limited number of measurement points (∼20) enables capturing the regional deformation pattern. The addition of a series of less than 5 supplementary points brings useful information to detect local anomalies of small-to-moderate (e.g. subsidence, with 1 km radius and 2 mm/y maximal amplitude) size for a known position. For detecting an unpredicted anomaly, the measurements network density needs to be largely increased, making the method more expensive. Though the results are not directly transposable in other settings, this experience feedback brings useful orders of magnitude and an original risk-oriented approach. [ABSTRACT FROM AUTHOR]

1.6 Mt of CO2 was injected in the Tubåen Fm. at the Snøhvit field from April 2008 to April 2011. Injection was associated with a pressure build-up, and following a well intervention operation, the Stø Fm. was used for further CO2 injection, avoiding the pressure limitations in the Tubåen Fm. The pressure build-up in Tubåen Fm. was mainly caused by a limited reservoir volume and heterogeneities in the formation. Salt precipitation was evaluated as a possible source that reduced the near wellbore injectivity with associated pressure build-up. Weekly injection of a 90:10 mixture of methyl ethyl glycol and water (MEG) was implemented to mitigate salt precipitation. This paper evaluates the causes for the pressure build-up in more details. Analysis of bottom-hole-pressure measurements (BHP) from periods of shut in indicates a low permeable zone surrounding the well at early stage of injection. The low permeable zone may be caused by precipitated salt reducing the injectivity. Salt precipitation is also observed to reduce the porosity and permeability on core plugs from the injection well in laboratory measurements. The Tubåen Fm. comprise of 4 sandstone units (Tubåen 1-4) separated by interbedded shale units. Comparison between synthetic seismograms and time-lapse seismic data indicate that CO2 propagated into the three lowermost Tubåen sandstone units (Tubåen 1-3), where the pressure also increased. The shale unit above Tubåen 3 sandstone unit appears sealing from the synthetic seismograms. Tubåen 1 sandstone unit has exceptionally good injectivity. This may have a negative impact on the overall storage capacity by channeling the CO2 and increase the pressure locally. A dimming of the time-lapse seismic amplitude is observed that may be associated with the injected MEG. [ABSTRACT FROM AUTHOR]

CO2 injection in brine-saturated Bentheimer sandstone was studied experimentally to visualize and quantify salt precipitation in porous rock caused by evaporation of water into injected gaseous phase CO2. Gas and solid-salt saturation profiles were captured by μ-CT (micro computed tomography) and the pressure drop over the core was monitored continuously. The experimental results were compared with numerical simulations using the TOUGH2 reservoir simulator with the equation of state module ECO2N, and a numerical code that we have developed with an alternative approach on evaporation. Using the equilibrium phase partitioning model in TOUGH2, simulation results predict injectivity decline due to an accumulation of precipitated salt near the core inlet. This is in contradiction to our experimental observations, in which neither salt accumulation nor injectivity impairment was noticed. It appears that at near well injection velocities, local equilibrium phase partitioning used in the simulator overestimates evaporation of water into the CO2 gaseous phase. On the other hand, satisfying results were obtained from our model which uses a kinetic formulation for the evaporation. No injectivity impairment was found which is compatible with the experimental results. [ABSTRACT FROM AUTHOR]

We carried out stochastic inversions of InSAR data to assess the probability that pressure perturbations resulting from CO2 injection into well KB-502 at In Salah penetrated into the lower caprock seal above the reservoir. We employed inversions of synthetic data to evaluate the factors that affect the vertical resolution of overpressure distributions, and to assess the impact of various sources of uncertainty in prior constraints on inverse solutions. These include alternative pressure-driven deformation modes within reservoir and caprock, the geometry of a sub-vertical fracture zone in the caprock identified in previous studies, and imperfect estimates of the rock mechanical properties. Inversions of field data indicate that there is a high probability that a pressure perturbation during the first phase of injection extended upwards along the fracture zone ~150 m above the reservoir, and less than 50% probability that it reached the Hot Shale unit at 1500 m depth. Within the uncertainty bounds considered, we conclude that it is very unlikely that the pressure perturbation approached within 150 m of the top of the lower caprock at the Hercynian Unconformity. The results are consistent with previous deterministic inversion and forward modeling studies. [ABSTRACT FROM AUTHOR]

Highlights: [•] Demonstrated storage of CO2 in a partially saturated porous medium at 277K and 3.2MPa. [•] 37.5kg/m3 of CO2 in hydrate and gaseous form were stored. [•] This amount is 100% more than what can be stored in gaseous form at the same conditions. [•] 39–55% of the water converted into hydrate in 24h. [Copyright &y& Elsevier]

Highlights: [•] A coupled numerical approach is used to fully represent drying mechanisms. [•] The thermodynamic and physical processes are well simulated at lab scale. [•] Capillary properties of rock prevent a sudden evaporation of irreducible water. [•] A sufficiently high gas injection rate can overcome the capillary forces. [•] Porosity/permeability variations are anticipated according to brine salinity. [ABSTRACT FROM AUTHOR]

Highlights: [•] We ran experiments to study the drying of near wellbore of CO2 injection wells. [•] First, water is pushed according to a two-phase flow immiscible displacement. [•] Residual water might be transferred to gas phase by thermodynamic exchanges. [•] Any dissolved salt in the water can be transported by capillary flows. [•] The permeability can be altered by salt precipitation and pore clogging. [ABSTRACT FROM AUTHOR]

Highlights: [•] We simulate CO2 injection into the Springerville-St. Johns dome, an analog site. [•] Reservoir pressurization causes uplift and spreading of the overlying caprock. [•] Induced seismic risk is quantified by the change in Coulomb failure stress. [ABSTRACT FROM AUTHOR]

Highlights: [•] A static and dynamic model is presented for a producing CBM field in Qinshui Basin, China. [•] Dynamic model is history matched using the 16-month field data of 43 CBM wells. [•] A new purpose-build economic model is presented. [•] Well spacing for CBM production is optimised based on an integrated techno-economic approach. [•] Feasibility of ECBM for various injection gas compositions, injection timing, gas price and carbon credits is studied. [Copyright &y& Elsevier]

Abstract: We present the results of a high-resolution time-lapse crosswell seismic survey carried out at a large-scale CO2 injection pilot located in Cranfield, MS, USA. This dataset, spanning an injector and two monitoring wells, provided a detailed view of the boundaries and internal structure of the injection unit, the Tuscaloosa D/E sand. Time-lapse tomographic processing of one well pair revealed the signature of the injected plume, two zones of decreased P-wave velocity which spatially correspond to higher permeability sections of the reservoir unit. We then used White's model for patchy saturation, combined with secondary information from core and well-log measurements, to convert the imaged changes in P-wave velocity into estimates of supercritical (sc) CO2 saturation in the interwell region. Our estimate is relatively consistent with existing lithologic and core data as well as independent measurements of scCO2 saturation derived from pulsed neutron logging. While effective in mapping the zone of CO2 invasion in the interwell region, several sources of uncertainty still exist in quantifying saturation using crosswell seismic methods, including (but not limited to) the degree of mesoscale mixing or “patchiness” at scales below a seismic wavelength. [Copyright &y& Elsevier]

Highlights: [•] A numerical simulator is developed with advanced physical models to history match CO2 injection test results in Cranfield. [•] Numerical results were consistent with bottom-hole injection flowing pressure for the first 350 days prior to the rate increase. [•] Simulation results were consistent with the hypothesis of the development of high permeability flow paths when the injection rate was doubled. [•] CO2/brine relative-permeability curves and trapping model had a moderate impact on bottom-hole injection pressure. [Copyright &y& Elsevier]

Abstract: Continuous reservoir fluid pressure monitoring is a technique being deployed and evaluated for monitoring CO2 sequestration projects for storage integrity. Pressure data are known to reveal information about bulk reservoir properties and performance, and the pressure magnitude trajectory through time is commonly used as a metric for demonstrating numerical flow model conformance with observed injection history (i.e. pressure history match). Identification of well leakage using a pressure history approach can be difficult due to the subtle effects such leaks can have on the characteristic pressure magnitude evolution. Using a combination of theory, an analytically-derived synthetic reservoir pressure history example, and analysis of field pressure data, we develop a broadly applicable technique for analyzing reservoir pressure transients in continuous time series and illustrate how that technique can be used to quantify sensitivity to wellbore leakage in the field. Analysis presented here focuses on information provided by second derivative of the continuous pressure time series (d 2 P/dt 2 ). We show that d 2 P/dt 2 transients reveal consistent relationships with known (theoretical case) or induced (field case) pressure perturbations that are independent of prior pressure history, making them a very useful diagnostic tool for identifying and evaluating any observed transients of unknown origin (i.e. sudden well leakage events unrelated to injection schedule). To the degree that the onset of well leakage is expressed as a pressure transient similar to decreases in injection rates, we are able to identify the source functions (changes in flow rates from variable distances) that our gauges are (and are not) sensitive to. Observational data indicate that sensitivities in the field can be much lower than theoretical expectations, mostly a result of noisy and heterogeneous natural systems. Our analysis can be applied to other field scenarios with different reservoir properties for refining observation well placement design with predictable and quantifiable sensitivity. [Copyright &y& Elsevier]

Abstract: Understanding and predicting physical and chemical trapping mechanisms are important for designing successful CO2 storage projects. The processes have been investigated extensively by numerical modeling and, to a lesser degree, by laboratory experiments. The results of modeling and laboratory studies need to be verified at field conditions and scales. A variety of field data sets have been collected at the Cranfield CO2 injection and monitoring site of the Southeast Regional Carbon Sequestration Partnership (SECARB) where 3.54 million tons of CO2 had been injected by February 2012. Field characterization and extensive monitoring provide unique insights into the trapping processes that help in immobilizing injected CO2. The four-way closure of the injection zone ensures effective structural trapping of buoyant CO2 and maximum opportunity for chemical trapping. The fluvial reservoir shows a high degree of lithologic and petrophysical heterogeneity associated with multiple episodes of fluvial-channel incision and deposition. Variable diagenetic chlorite further exerts a complex overprint on rock properties because chlorite grain coatings prevent quartz cementation and preserve porosity. CO2 solubility in the brine under the field condition is approximately 36g/L (9kg/m3 rock volume). The CO2–brine contact area is maximized within the sinuous and focused flow pathways that could increase dissolution. Yet geochemical reactions are found to be very slow in the reservoir. Mineral trapping capacity is limited because the reservoir rocks contain only trace amount of reactive minerals that supply cations to convert CO2 into carbonate minerals. Two parallel multiphase flow experiments show that CO2 residual saturation varies significantly between conglomerate and sandstone (31% and 3.5%) facies in the reservoir, which complicates estimates of residual trapping capacity. [Copyright &y& Elsevier]

Highlights: [•] Injection of 20kt of CO2 during 2013/2015 at Hontomin (Burgos, Spain). [•] The CO2 flux baseline, including its seasonal variability, was defined. [•] The soil–atmosphere CO2 fluxes are low and fed by a biological source. [•] Reference CO2 flux values above a possible leakage were assessed. [•] These data are useful for intra- and post-injection monitoring programs. [Copyright &y& Elsevier]

Highlights: [•] Simulation of CO2 injection into the Bunter Sandstone Formation was performed. [•] Storage efficiencies of closed structures were derived. [•] Calculated storage efficiencies for closed structures range from 4% to 33%. [•] Storage efficiency highly sensitive to reservoir heterogeneity and structure. [•] Laterally continuous impermeable layers are critical factors controlling storage efficiency. [Copyright &y& Elsevier]

• Accurate in-situ estimation of CO 2 residual trapping at field scales, requires a deep understanding of processes/phenomenon that affect gas phase immobilization at various scales. • Critical gas saturation is an important characteristic parameter which determines at what saturation the trapped gas can be remobilized, thus a key parameter in estimating in-situ residual trapping at field scale. • Including the concept of critical gas saturation into relative permeability functions helps interpreting the field scale push-pull tracer experiments. Residual trapping of CO 2 , typically quantified by residual gas saturation (S gr), is one of the main trapping mechanisms in geological CO 2 storage (GCS). An important additional characteristic parameter is critical gas saturation (S gc). S gc determines at what saturation the trapped gas remobilizes again if gas saturation increases due to exsolution from the aqueous phase, rather than from further gas injection. In the present study, a pilot-scale CO 2 injection experiment carried out at Heletz, Israel, in 2017, is interpreted by taking critical saturation into account. With regards to this experiment, the delayed second arrival peak of the partitioning tracer could not be captured by means of physical models. In this work, the hysteretic relative permeability functions were modified to account for S gc. The results showed that accounting for the effect of S gc during the secondary drainage indeed captured the observed delayed peak. The difference between the values of S gr and S gc , influenced both the time and peak height of the tracer arrival. To our knowledge this is first time that critical gas saturation has been considered in field scale analyses related to GCS. Accounting for S gc is relevant where gas saturation during secondary drainage increases due to gas phase expansion or exsolution from the aqueous phase. This will happen in situations where pressure depletion occurs, e.g. due to gas leakage from fracture zones or wells or possibly because of pressure management activities. The findings also have implications for other applications such as underground gas storage as well as for geothermal reservoir management. [ABSTRACT FROM AUTHOR]

• Passive acoustic techniques can be used to identify and quantify underwater gas release. • We propose an adaptive single bubble identification technique, incorporating bubble acoustic characteristics of time, frequency and strength. • In a controlled gas release experiment, the bubble radius is acoustically determined as 0.15–0.3 cm, and optically determined as 0.2–0.5 cm. • The gas flux is acoustically estimated as 32–88 kg/day in response to a known gas injection flow rate 143 kg/day. Passive acoustic techniques can be used to identify and quantify underwater gas release at natural sites, or at locations related to anthropogenic activities. There are still significant issues in extracting bubble signals from background noise, particularly for bubble counting and sizing techniques relying on inversion of the time-averaged acoustic spectrum. In this work we propose an adaptive single bubble identification technique, which incorporates bubble acoustic characteristics including pulsation time interval, frequency bandwidth and radiation strength. The method applies a cross-spectrogram, enabling an increase in signal-to-noise ratio resulting in a reduction of the false alarm rate on bubble identification. We demonstrate this technique using an array of hydrophones to determine the bubble size distribution and gas flux at a controlled CO 2 release site, 4 m beneath the seabed, at 120 m water depth in the central North Sea. The results show that the bubble radius, as estimated using acoustics has a distribution with a peak in the 0.15–0.3 cm range, while an estimate based on optical method suggests a range of 0.2–0.5 cm. The gas flux is acoustically estimated as 32–88 kg/day in response to a known gas injection flow rate 143 kg/day, indicating 22–62% of the injected CO 2 is emitted from the seabed in gaseous form, with the remainder being trapped, or dissolved. [ABSTRACT FROM AUTHOR]

Highlights: [•] We discuss a theoretical concept for improved CO2 confinement in saline formations. [•] The concept involves the injection of fly ash slurry and CO2 in separate wells. [•] CO2 combined to mineral slurries injection causes pressure build-up. [•] This pressure build-up could be managed by extracting formation brine. [•] The technological feasibility of the concept is not addressed here. [Copyright &y& Elsevier]

• Salt precipitation in dual- and multi-porosity systems compared to monomodal systems. • Permeability reduction of up to three orders of magnitude observed. • Capillary-driven transport between micro- and macro-porous system responsible for permeability reduction. • Volumetric ratio of micro to macro porosity and water salinity and saturation are controlling parameters. Drying of geological formations by supercritical gas injection and the associated precipitation of salts from the formation water may have serious consequences for upstream operations in terms of injectivity/productivity impairment. The potential effect on the formation permeability near the injection well is controversially discussed in literature with some studies finding a strong and others no impairment. In an earlier publication (Ott et al., 2014), we argue that this is related to the microscopic pore structure and capillary-driven brine transport therein, and that in well sorted sandstone reservoirs, permeability may be less affected than in dual- or multi-porosity systems. In the present paper, we investigate the consequences of dolomite-formation drying due to the injection of under-saturated supercritical CO 2 into samples from a Middle-East dolomite formation. Compared to earlier reported results on sandstone, the experiments show a complex behavior with a much larger effect on permeability. A permeability reduction of up to three orders of magnitude has been found. This is explained by a simple numerical model on local capillary-driven flow of water from micro- to the macro-porous regions at low brine saturation where evaporation dominates desaturation. The model suggests salt precipitation in the CO 2 conductive macropores, which impacts the effective CO 2 permeability. The volumetric ratio of micro to macro porosity, the capillary pressure contrast and water salinity and saturation are identified as the controlling parameters. [ABSTRACT FROM AUTHOR]

• Two dedicated field experiments carried to quantify the CO 2 residual trapping in-situ at 1.6 km depth. • The experimental procedures and results of these experiments are presented. • Hydraulic withdrawal test as a characterization method was robust and gave a clear signal. • Tracer experiments can give more detailed information of CO 2 residual distribution but are more complicated to carry out. Two dedicated field experiments have been carried out at the Heletz, Israel pilot CO 2 injection site. The objective has been to quantify the CO 2 residual trapping in-situ, based on two distinctly different methods. Both experiments are based on the principle of a combination of hydraulic, thermal and/or tracer tests before and after creating the residually trapped zone of CO 2 and using the difference in the responses of these tests to estimate the in-situ residual trapping. In Residual Trapping Experiment I (RTE I), carried out in autumn 2016, the main characterization test before and after the creation of the residually trapped zone were hydraulic withdrawal tests. In this experiment, the residually trapped zone was also created by fluid withdrawal, by first injecting CO 2 , then withdrawing fluids until CO 2 was at residual saturation. The second experiment, Residual Trapping Experiment II (RTE II), was carried out autumn 2017. In this experiment, the residually trapped CO 2 zone was created by CO 2 injection, followed by the injection of CO 2 -saturated water, to push away the mobile CO 2 and leave the residually trapped CO 2 behind. In this test, the main reference test carried out before and after creating the residually trapped zone was injection and recovery of gas partitioning tracer Krypton. This paper presents the experimental procedures and results of these experiments. A hydraulic withdrawal test as a characterization method was robust and gave a clear signal. Given the difficulties in injecting water optimally saturated with CO 2 , in order not to dissolve the residually trapped CO 2 or to create situations with excess mobile gas, withdrawal test may also be a generally preferable hydraulic testing method, in comparison to injection. The limitation of any hydraulic test is that it only gives an averaged value over the test section. At Heletz additional information about CO 2 distribution was obtained based on thermal measurements and by monitoring the pressure difference between the two sensors in the bolehole. The latter could be used to estimate the amount of mobile CO 2 in the well test section. Tracer experiments with gas partitioning tracers can in principle give more detailed information of CO 2 residual distribution in the reservoir than hydraulic tests can, but are also far more complicated to carry out, involving sophisticated and sensitive equipment. In the Heletz case the optimal injection of CO 2 -saturated water turned out to be difficult to achieve. Creating the zone of residual saturation by means of fluid withdrawal rather than by injecting CO 2 -saturated water seemed a more robust approach. Monitoring the gas contents in the test interval gave good guidance on the state of the system. Model interpretations of the two experiments to obtain values for CO2 residual saturation are presented in companion papers in this same Special Edition. [ABSTRACT FROM AUTHOR]

• A new non-isothermal wellbore/reservoir model with phase transition for CO2 injection is developed. • The model is successfully applied to simulate the coupled thermal-hydrodynamical process in the Ordos CCS project. • The wellbore heat exchange between the injected CO 2 and the surrounding rock plays a critical role. Non-isothermal flow in wellbores and geological formations is an important process associated with geologic storage of CO 2. Technically, simulation of it is a highly challenging task as it often encounters phase transition problems for the fluids involved, which may greatly influence the profiles of pressure, temperature, and flowrate along the wellbore and consequently changes the injectivity of the relevant gas injection. In this paper we present a coupled non-isothermal wellbore/reservoir model for simulating the relevant flow behaviors, in which the non-isothermal wellbore flow model CO2Well and the reservoir simulator TOUGH2/ECO2N are combined to form a novel coupled flow model. The model developed is compared and verified by the existing wellbore-reservoir simulator T2Well with two CO 2 injection examples. These examples demonstrate that the present method has considerable computational advantages in simulating wellbore flows when phase transition occurs. We then apply this model to the Ordos CCS demonstration project in China, and investigate the sophisticated, thermal-hydrodynamically-coupled flow processes observed there owning to injection of the condensed, cold CO 2 that was directly captured from a nearby coal liquefaction plant. The results obtained by the simulation, along with the relevant field observations, provide in-depth insights into the CO 2 flow behaviors in both the wellbore and the geological formation. For example, the simulation revealed that, in the wellbore, the heat exchange between the injected CO 2 and the surrounding rock plays a critical role for the temperature distribution. It was also observed that phase transition occurred in the transferred period between the injection time and the shut-in time. In addition, both the simulation and field observation showed that most CO 2 injected entered the topmost layer due to the high transmissivity of the rock. The simulation also showed that the temperature-change zone travelled slower than the CO 2 plume. For example, the CO 2 plume extended to 430 m away from the injection site after 31 months of CO 2 injection, while the temperature-change zone extended merely about 90 m away, much smaller than that of the CO 2 plume. The simulation suggests that the injectivity at this site is about 0.83 kg/(MPa·s). The simulation also suggests that the injection temperature should be relatively high (e.g., above −3 °C if the injection rate is more than 9.45 kg/s) to avoid formation of CO 2 hydrate in the subsurface. [ABSTRACT FROM AUTHOR]

• Multiphase CO 2 wormholing (WH) models have been validated on existing and new data. • Hydrochloric acid WH growth correlations were succesfully adapted to CO 2. • Dry CO 2 injection operations are likely to result in near-uniform dissolution. • Water injection without dissolved CO 2 and CO 2 WAG tend to cause slow WH growth. • Carbonated water injection or high-rate CO 2 + water co-injection tend to cause rapid WH growth. Carbon dioxide (CO 2) injection into geological formations is gaining global interest. Examples include CO 2 storage to mitigate greenhouse gas emissions and water alternating gas (WAG) injection for enhanced oil recovery (EOR) and storage. Injected CO 2 inevitably dissolves in water (injected or formation), which results in acidic conditions that can dissolve the rock matrix in carbonate reservoirs. Depending on the dissolution's location and pattern in the reservoir, this may benefit well injectivity and/or threaten well integrity. Fine-gridded models with detailed physics and chemistry capture the relevant effects but are not suitable for the application to the field scale where instead correlations are used. The correlations that exist, however, are so far not sufficiently constrained to be of practical use. We report new experimental and modelling work that provides the means for qualitative to quantitative field-scale predictions of these effects for all the different combinations of CO 2 –water injection of interest. These show that, for conventional injection strategies (dry CO 2 injection and WAG), there are no material concerns, but there are potential well integrity issues that need more detailed investigation for the proposed alternative strategies of carbonated water injection or co-injection. [ABSTRACT FROM AUTHOR]