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A casing heat exchanger is investigated for use in the thermal energy storage system. With supercritical compressed air (CA) as working fluid, both the thermal oil and water are adopted as the heat-transfer mediums to analyze the heat transfer performance of the casing heat exchanger. The different flow pathways are developed and solved numerically by exchanging the pathway of heat source and cold source in the heat exchanger. Then, the effect of pressure and inlet mass flux of compressed air are investigated. The simulation results indicate that the temperature increase of water is smaller than the increase of thermal oil because water has large heat capacity and requires large amount of latent heat. Heat transmitting performance of heat exchanger is better when thermal oil travels inside the central tube and supercritical CA flows through the outer tube. With higher pressure and larger inlet mass flux of compressed air, the temperature and heat exchange will increase.

During CO2 injection, a microannulus will be generated, leading to the transmission of gas through the cement behind the casing or before the formation when thermal stress exceeds bond strength. In this work, leakage channel prediction model was developed to predict the leakage channel of CO2 injection wells. The prediction results indicate that the thermal stresses first decreased and then increased with increasing well depth; decreased with increasing radial distance; and increased with increasing injection time. The cement sheath of a production casing is more likely to form a leakage channel than other cement sheaths during long-duration CO2 injection.

1. Though multistage axial turbines are being widely used since many decades for water steam expansion or in gas turbines, their use in ORCs has traditionally found limitations as a consequence of the choice of designing turbines with cantilever arrangements. 2. The choice of the cantilever arrangement is mainly related to the advantages of having simple shaft bearings design, only one rotating seal system in contact with the working fluid, a lighter and more compact turbine casing, only one side of the turbine casing occupied with the bearing and sealing systems (leaving the other side free to host the outlet duct for working fluid expanded vapour which often features very large volumetric flow rates), easiness of access for ordinary and extraordinary maintenance. Hence cantilever arrangement involves definitely lower turbine costs, both in terms of Capex and Opex and is practically the only solution adopted by the industrial suppliers of ORC turbines. 3. By adopting the cantilever arrangement the installation of several turbine discs hosting several expansion stages, traditionally installed one close to the other, would increase the overhang mass of the turbine rotor and decrease the natural frequencies of the system, yielding some mechanical problems and, at the end, limiting the possibility of installing, practically, more than 2-3 stages with this kind of arrangement. 4. On the other hand, however, modern ORC turbines require to increase number of stages to better exploit the expansion enthalpy drop, in order to increase turbine efficiency and/or to allow to adopt a low rotating speed (even 1,500 rpm) for a direct connection with synchronous generator. 5. The paper will describe an innovative solution that has allowed to increase the number of stages from the traditional 2-3 to at least 5 without leaving the effective cantilever arrangement, keeping the concept of ‘rigid’ rotor (i.e. operating below the first flexional natural frequency), with very low measured vibrations. 6. Operating data of a 9 MW 5 stage ORC turbine put in operation in 2016 will also be presented.

At the Ketzin CO 2 storage site, Germany, an interdisciplinary, comprehensive monitoring concept focusses on the storage complex, the overburden, the surface and the wellbores. Well integrity as one key requirement for safe storage operation has been monitored by combined video inspection, pulsed neutron gamma logging PNG, magnetic imaging defectoscopy MID and continuous annuli pressure monitoring. The time-lapse MID derived casing thicknesses are within the production specifications, conform to the API standards, and provide no hints to time dependent changes or to any other signs of corrosion. The comprehensive monitoring data indicate well integrity throughout the entire Ketzin life-cycle.

This paper presents a new method to monitor caprock and wellbore integrity at CO2 storage sites by utilizing the Distributed Fiber Optic Sensing (DFOS). DFOS has an advantage to measure temperature and strain at any point in an unprocessed optical fiber, contrary to the conventional Fiber Bragg Grating (FBG) sensing which measures temperature and strain at a limited number of discrete points along the processed fiber cable. To put the DFOS technique into the practical use at the CO2 storage sites, we measured the frequency shifts of the Rayleigh and Brillouin scattering in an optical fiber attached to a sandstone sample under hydrostatic pressure, and also measured strain of the sample by conventional strain gages simultaneously. We applied the DFOS technique to our filed experiments when injecting and extracting fluid from a shallow well. The shallow well was drilled to a depth of 300m and three optical fiber cables were installed behind well casing for detecting impacted zones along the well depth direction. With this permanent installation behind casing, we successfully detected the deformed zone during the fluid injection and extraction tests. The field results suggest that the DFOS technique can be used in geomechanical monitoring of caprock and wellbore integrity by providing deformation details such as which depth and how much the target layer deformed in subsurface.

Wells play a key role in the reduction of greenhouse gas emissions. They are not only a critical element in ensuring the permanent trapping of carbon dioxide (CO2) in deep subsurface permeable formations, but they are also being recognized as an important source of natural gas emissions. The goal of well integrity is to minimize fluid migration from permeable formations through the use of barriers. Traditionally natural and man-made barriers have been regarded as separate and independent components: once the original impermeable layers such as shale or halite have been pierced by drilling, isolation must be restored by installing steel pipe and annular cement. However this picture has been blurred by the growing recognition that a particular class of rocks can prevent and control fluid leaks through a well's life, including the hundreds of years after abandonment. Creeping formations such as halides, mudstones and possibly ice can seal uncemented sections and large defects in the cement sheath. More importantly, the radial stress they exert reduces debonding and restores integrity once the cause of a microannulus has been eliminated; this makes the geological barriers self-healing, or robust. If creeping formations are to become a fundamental element in well design and evaluation, they need to be properly understood and modeled. From an engineering point of view, the identification and characterization of geological barriers should provide four sets of constitutive properties: • The ultimate radial stress exerted by the formation, as well as its anisotropy (i.e its variation around the casing circumference). • Mechanical properties of the formation to estimate leakage rates if the closure stress has been overcome and a microannulus is formed. • A time scale over which the creep deformation can seal a given defect, or an uncemented section of the annulus. • The type and extent of geochemical reactions, if any, between the formation and the leaking fluid. This paper reviews the limited available evidence on the role and characteristic of geological barriers and adds new examples that have arisen from the study of well integrity at the basin scale. A simple model captures the essential characteristics of the formations’ behavior and allows identifying the key parameters that control the beneficial aspect of formation creep on well integrity. For a cross-section at a given depth, we model the well system (casing/cement / formation and the potential defects at the interfaces) under plane-strain condition. Modeling formation creep using viscoelasticity, we obtain the time of closure of a given set of defects between the formation and the steel casing. In the absence of defects, or when the defects have already been closed, we also obtain the time evolution of the radial stress clamping the interface. The intensity of such a normal compressive stress clamping the interfaces is the key parameter controlling the occurrence of micro-annulus induced by subsequent fluid injection, such as CO2 injection, natural gas storage or reservoir stimulation. We use both an analytical approach in the simplest case of an isotropic far-field stress and a boundary integral equations method in the Laplace domain to handle more complex configurations. Our method is notably agnostic with respect to the viscoelastic constitutive law chosen to model the geological formation time-dependent behavior. We further discuss the impact of the choice of the type of constitutive law on the obtained results. Lastly, we discuss how the controlling parameters of the problem (in-situ stress, creep formation properties) can be measured or estimated from geophysical logs, geological and geomechanical information as well as active well tests. Our analysis aims at assessing the state of the art in the design and evaluation of geological barriers from a well integrity perspective. We also highlight the remaining questions to be answered by research.

Assessment of well integrity has become more important for CCS and CO 2 -EOR as it has become apparent that wells represent the most likely migration pathway for CO 2 to leave a CCS storage unit or a CO 2 -EOR reservoir. Although wells represent a migration pathway they are also the best vehicle for employing technology monitoring CO 2 injection and storage. This contradiction of being a potential migration path and key monitoring technology leads to a need to understand how monitoring wells may be similar or different in comparison to other types of wells with respect to migration risk. The maturation and completion US Department of Energy sponsored research projects presents an opportunity to assess the integrity of monitoring wells that have been exposed to injected CO 2 . This paper discusses an integrity assessment of two monitoring wells in an operating CO 2 -EOR flood in Mississippi, USA. It provides an early assessment of how monitoring equipment affects well integrity and isolation capacity. Each of the monitoring wells in this study were similarly constructed using both fiberglass and conventional steel casing. Each of the wells was instrumented with multiple monitoring technologies including, electrodes, pressure gauges, and temperature sensors on the outside of the casing. Control lines and cables were run from the surface on the outside of the long-string casing in each well to communicate with the monitoring equipment. A comprehensive logging, testing, and sampling program was developed to assess integrity in both wells. Ultrasonic well mapping was used to create radial maps of the location of cement, liquid, and gas behind the casing. Cement bond logging provided information on the casing-to-cement and cement-to-formation bonds for the long-string section. The logs showed that the monitoring equipment attached to the long-string casing is visible as continuous low acoustic impedance features and may represent a leakage risk. Cased-hole sidewall cores were collected and provided some validation of the log results and provide local information on the isolation capacity of the wells. The combination of information from the log data sets and cores was used to assess isolation capacity. The results of the study show that careful design and assessment of the materials used in monitoring well construction, the types of monitoring technology, and the location of monitoring technology within a well needs to be conducted with limiting migration potential and maximizing well integrity as objectives.

The Mont Terri Underground Research Laboratory (MT-URL) and Consortia affords member organizations the opportunity to bridge the gap between bench and large field scale experiments. At this underground test site, CCP4 (CO 2 Capture Project Phase 4) partners, a four company collaboration that includes BP, Chevron, Petrobras and Suncor, along with the Swiss Topographic Survey (swisstopo) who operates the laboratory, are conducting 1) an experiment that focuses on the mitigation of pressure leakages associated with CO 2 containment in near wellbore injection well systems using novel sealants and, if resources are available, 2) a fractured caprock breach sealing experiment. The mock well system experiment for CO 2 breach mitigation is of immediate interest. This experiment, designated CS-A, is operational with equipment installation accomplished late 2 nd quarter 2015 and experimental protocols that commenced late December 2015 scheduled to run through the summer of 2017. Sealant testing is scheduled to begin in late 2016. The objective is to assess the ability to characterize and seal induced leaks at micro annular interfaces (casing, cement and country rock) using novel sealants with determination of the long term sealing integrity. The 2 nd experiment is in an earlier stage of development, having been scoped in 2014 for costing and resource alignment. This second project requires additional participants to spread costs before the final design is set.

Many depleted oil and gas reservoirs are targets for commercial CO 2 enhanced oil recovery, resulting in associated CO 2 storage which occurs as part of the process. These oil fields have legacy wellbores that may contain a leakage pathway. Corrosion or degradation can occur anywhere along the wellbore through or along the cement, casing, tubing, or plugs and is a challenging issue facing the oil and gas industry. Two case studies presented here are legacy wells in the Weyburn oil field with substantially different CO 2 injection rates. These case studies aim to help understand casing corrosion in CO 2 -rich environments.

Wellbore integrity is critical to long term carbon storage. During CO2 injection, changes in temperature may result in large stress variations that can damage the well, threatening its integrity. The different materials comprising the wellbore and near-wellbore environment (namely the casing, cement and surrounding rock) possess different thermal properties. Consequently, there can be considerable variations in both material properties and thermal gradients across these layers, resulting in different amounts of contraction and expansion of these materials. This may generate sufficient thermal stresses to lead to fracture within the cement and/or host rock, or delamination of the cement/casing or cement/rock interfaces. Downsized wellbore samples have been used in laboratory studies to investigate the failure modes and failure criteria during thermal cycling operations. However, it is not clear to what extent such results can be reliably used to predict well failure at field scale conditions. In this work, we conduct a parameter study involving the size and material properties of the wellbore samples subjected to different rates of thermal loading, with the objective of predicting how these parameters can affect the thermal stress in field scale well conditions. A state-of-the-art parallel multiscale, multiphysics code named GEOS, developed at Lawrence Livermore National Laboratory, was used to study the thermal response of wellbore materials. A finite element solver considering linear elastic materials was coupled with a finite volume heat equation solver to simulate the wellbore deformation and fracture during thermal cycling. To understand the effect of wellbore size on thermal fracturing, simulations were conducted at different height to diameter ratios. The wellbore sample size was systematically varied from the lab scale to field scale with several intermediate scales. The change in thermal stresses were compared for different scales. Additionally, the effect of elastic modulus and cooling rates were studied.

Avoiding CO2 leakages from storage reservoirs is crucial to ensure safe and cost-efficient Carbon Capture and Storage (CCS). This can only be done if effort is made to maintain well integrity throughout the entire life-cycle of a well. Cement integrity is especially important, since the interfaces between cement and rock or casing have been identified as weak links in today's well construction. The present paper focuses on the healing of fractures in well cement when the material is exposed to a CO2-brine water-alternating-gas (WAG) flooding scheme. Specimen characterization using computed tomography combined with electron microscopy documents the self-healing procedure in detail for a composite cement-rock specimen subjected to a WAG flooding scheme. The study revealed volumetric data on self-healing of cement cracks and chemical changes in the specimen as well as in aqueous chemistry upon CO2 exposure. The measured aqueous chemistry suggests CO2-cement interaction to be less pronounced with time thereby together with the observed cement self-healing suggesting that the risk of compromising the safety of a storage site by cement-CO2 chemical reactions is minimal.

As part of the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL) sponsored project, The Quantification of Wellbore Leakage Risk Using Non-destructive Borehole Logging Techniques, the construction and integrity of a 68 year old well was studied. This study builds upon previous work examining the integrity of existing wells through shale formations. The objective of this study was to measure well integrity through potential caprocks and aid in understanding the potential leakage risk posed by old wells that intersect CO2 injection projects. The well was originally completed as a production well in the Gulf Coast region in 1945 and then plugged and abandoned in 1969. The well was re-entered and re-completed as an observation well for a CO2 injection project in 2008. It was replugged and abandoned after completing its observation role in 2013. For this study the well was logged using cement bond log and ultrasonic mapping tools, tested and sampled using a dynamic tester, and cored using a sidewall coring tool. The age of this well makes it the oldest well to be studied in this manner and this is the first well to be studied this way in the region. The results of the study indicate that much of the material behind the casing is unconsolidated cement. Logging results in many places in the well show poor isolation potential and indicate a microannulus. The logs also indicate removal of material during hydraulic testing which was confirmed by laboratory analysis. Of the six cores collected, four consisted of unconsolidated, soft, cement or rock, one consisted of heavily altered cement, and one consisted of slightly altered cement. The results of study are an interesting contrast to earlier field studies because they show an old well that lacked integrity at most of the test and sample points. However, the logging and a core sample in the squeezed zone indicate that there was zonal isolation between the injection and monitoring zones. The logging and mapping data along with the analysis of the “core” material collected provide insight into the potential leakage pathways within the well.

Every CO2 capture and storage chain will contain injection wells. The most important common operations for wells are shut-ins and depressurizations for reservoir characterization, maintenance stops and testing of valves. The aim of this work is firstly to demonstrate the need for experiments on these operations. Secondly, a new experimental set-up is proposed for such experiments. The main conclusion from this paper is that the physical phenomena during shut-ins and depressurizations of CO2 injection wells can be described with models, but that that there are still some uncertainties left. The largest uncertainties occur when the transient flow is rapid and/or CO2 is mixed with water. The proposed experimental set-up consists of a well with casing to be drilled vertically 200-250 meter at the Statoil laboratory in Trondheim, Norway. A U-tube with two legs with different diameter will be suspended in the well. Moreover, water or brine can be added for observing the effects of the H2O-CO2 interaction. The U-tube is to be linked to the existing CO2 transport test facility, which has the necessary vessels, compressor and pump. This rig will hopefully contribute in making CO2 injection wells even safer and more cost efficient.

Many demonstration projects conducted in recent years have proved that CO 2 capture and geological storage (CCS) can be an effective technology to reduce the emission of the greenhouse gases. The prospective storage sites under investigation mainly include deep saline aquifers, depleted oil and gas reservoirs and unminable coal seams, which should have huge storage capacity to sequestrate CO 2 safely and permanently. Technically, the CCS method is feasible and can be acceptable to the public, but the storage safety and the economics of the CCS projects are of the main concerns. There are mainly three types of leakage pathways, including the failure of injection or other wells in the storage sites, undiscovered faults or fractures and seepages of cap rocks, and newly formed fractures during CO 2 injection process. For CO 2 storage in depleted oil and gas reservoirs, poor well integrity can be the main reason for CO 2 leaks, in which CO 2 can be leaked through cracks generated in cement ring or at the interface between casing and cement to upper formations. It is proposed that chemical method can be used to enhance sealing in failed wellbore or to block the leakage in near wellbore formations, since chemicals (solution) can be readily injected into wellbore or to where they are needed to form sealing packs as measures of precaution or emergency remediation. In this study, an innovative method for blocking CO 2 leakage is proposed, which is based on CO 2 -sensitive chemicals to formulate selective agents and can associate with other common technology such as cementing to enhance the sealing of leakage pathways. The CO 2 -sensitive chemicals are referred to that, when they encounter the leaked CO 2 in the formation or in wellbore, reactions will be triggered by CO 2 to form gel or solid structure inside the leakage pathways, because CO 2 is an active chemical that can take part in reaction or generate acidic environment when it dissolves into the water. The selection and design of the chemicals are based on two mechanisms: (1) certain polymers and resins will take part in crosslink reactions when CO 2 appears in their aqueous solution, resulting in gelation or solidification. (2) CO 2 can react with certain compounds in aqueous solution, in which precipitation will occur or solid can be produced to form blocking substance. In the paper, the CO 2 -sensitivity of some selected chemicals have been demonstrated in terms of generation of gels and blocking structures through visualization experiments and gel strength measurements. The chemicals studied include polyacrylamide, sodium aluminate, and phenolic resin. Their blocking capability was evaluated via core and sandpack flooding experiments, and the effects of important influencing factors on the chemical reaction and gelation prevailed at reservoir conditions are investigated, including the formulation and concentration of the chemicals, temperature, pressure and the salinity of formation water. The experimental results show that polyacrylamide and CO 2 can react via a cross-linking mechanism, in which gelation with a class H visual strength has been observed at 70°C and 1MPa. Good blocking performance was also achieved at sandpack flooding conditions. The solution of sodium aluminate can react with CO 2 and generate solid Al(OH)3 under high pressure and temperature conditions, which can significantly reduce the permeability of sandpacks or form a blockage for the moving CO 2 . The reaction product of CO 2 -cured resol phenol-formaldehyde resin exhibited good blocking strength. These results can provide guidelines for the design and deployment of CO 2 sensitive chemicals for blocking or enhancing the sealing of CO 2 leakage pathways in geological formation and wellbores.

Microbubble CO 2 can be generated by injecting CO 2 through special porous filters attached to borehole casing or gas tubing. When injecting microbubble CO 2 into saline aquifers, dissolution of injected CO 2 into formation water can be accelerated up more than 20%, compared to conventional CO 2 injection. As a result, microbubble CO 2 injection will minimize the free CO 2 fraction in the subsurface and consequently contribute to the long term safety of large-scale CO 2 storage. Microbubble CO 2 injection will also lead to effective use of pore space within the reservoirs. P-wave velocity and resistivity changes obtained when injecting CO 2 in microbubble and normal bubble sizes into artificial brine-saturated porous sandstones indicate more pore water displaced by the injected microbubble CO 2 in terms of sweep efficiency. Combined effects of enhanced dissolution and sweep efficiency in microbubble CO 2 injection can reduce the potential risk of CO 2 leakage from the subsurface and enable us to store more CO 2 in same reservoirs compared to normal CO 2 injection as well as economic benefit of achieving higher oil recovery.

Assessment of potential CO 2 and brine leakage from wellbores is central to any consideration of the viability of geological CO 2 sequestration. Depleted oil and gas reservoirs are some of the potential candidates for consideration as sequestration sites. The sequestration sites are expected to cover laterally extensive areas to be of practical interest. Hence there is a high likelihood that such sites will contain many pre-existing abandoned wells. Most existing work on wellbore integrity has focused on field and laboratory studies of chemical reactivity. Very little work has been done on the impacts of mechanical stresses on wellbore performance. This study focuses on the potential enhancement of fluid flow pathways in the near-wellbore environment due to modifications in the geomechanical stress field resulting from the CO 2 injection operations. The majority of the operational scenarios for CO 2 sequestration lead to significant rise in the formation pore pressure. This is expected to lead to an expansion of the reservoir rock and build-up of shear stresses near wellbores where the existence of cement and casing are expected to constrain the expansion. If the stress buildup is large enough, this can lead to failure with attendant permeability enhancement that can potentially provide leakage pathways to shallower aquifers and the surface. In this study, we use a numerical model to simulate key features of a wellbore (casing, annulus and cement) embedded in a system that includes the upper aquifer, caprock, and storage aquifer. We present the sensitivity of damage initiation and propagation to various operational and formation parameters. We consider Mohr-Coulomb shear-failure models; tensile failure is also likely to occur but will require higher stress changes and will be preceded by shear failure. The modeling is performed using the numerical simulator FEHM developed at LANL that models coupled THM processes during multi-phase fluid flow and deformation in fractured porous media. FEHM has been developed extensively under projects on conventional/unconventional energy extraction

A systematic investigation was completed to evaluate wellbore integrity factors for oil and gas wells in the Midwestern U.S. in relation to CO 2 geosequestration. In this region, over one million oil and gas wells have been drilled, and there is a perception that many areas are not suitable for geosequestration. The project focused on Michigan and Ohio as study areas. Records were obtained for over 280,000 wells. Plugging and abandonment reports were tabulated for 1,730 wells, and 278 cement bond logs were analyzed with a systematic method to grade the cement present in the well. Sustained casing pressure was monitored and analyzed for cement defect factor on thirteen wells in various configurations. The data was summarized with maps and graphs. The test site assessments provide examples of the steps and costs necessary to address wells in the region. Results indicate that a variety of well construction and plugging approaches were used over time, but many of the geologic formations being considered for CO 2 storage are not penetrated by many wells. The project provided practical tools for CO 2 storage applications including: database of well parameters, systematic cement bond log evaluation tool, and sustained casing pressure analysis method for cement defect factor.

For reliable risk assessment of carbon dioxide capture and storage (CCS), it is very important to predict the behavior of migration of injected CO 2 in relation with time and space under the environment of underground. Especially, it is important to estimate the amount of storage and leakage of injected CO 2 by way of both experimental and simulation study. In this study, we conducted experimental study about flow behavior of supercritical CO2 and water in porous media. The experiment was conducted to optimize relative permeability curves in the process of CO 2 injection, and it resulted that 1) water mobility was relatively high compared with that of CO 2 when grain size was large and 2) relative permeability to CO 2 became higher under the condition below critical point of CO 2 . In addition, we interpreted transport phenomena of CO 2 after shutoff of CO 2 injection that 1) liquid CO 2 easily migrated into geological formation in the cases of small grain size and low temperature and 2) dissolved CO 2 migration due to groundwater flow contributed to the change of CO 2 distribution under the condition of high water saturation. Then we considered some scenarios of leakage around injection well and migration of CO 2 through numerical study. We constructed a simple strata model, which is consisted from a reservoir layer, a cap rock layer and upper layer. To discuss the effect of reservoir depth, we set a couple of model strata: (a) upper limit of reservoir -800 m level, thickness of cap rock is 200 m, and (b) upper limit of reservoir is -200 m, thickness of cap rock is 100 m. In addition, we set four combinations of horizontal and vertical permeability for reservoir: (a) 500 mD, 100 mD, (b) 50 mD, 10 mD, (c) 500 mD, 10 mD and (d) 50 mD, 100 mD. Porosity is uniformly set to 0.4. On the other hand, permeability value of upper layer is set to 1000 mD. The surface temperature is 20 deg.C and thermal gradient is 3 deg.C/100m. To analyze effect of fail in well casing and/or cementing, we defined a gap between the well casing and surrounding layer. The gap has thickness and different geological conditions with surrounding layers. For gap, we set various permeability and 2 scenarios of leakage: (a) crack covers cap rock level, (b) crack covers entire well depth from bottom to surface. The CO 2 injection rate is 1 million ton/year and duration is 50 years. Using the constructed injection model, we carried out some simulation run using TOUGH2-CO 2 by LANL. As the result we obtained the relation between injection volume and the amount of CO 2 leakage through the gap model, and distribution of CO 2 in the model layer. We considered the effect of each parameter on flow behavior of CO 2 on gap model and quantified the amount of CO 2 leakage. These results will be implemented to the risk assessment system GERAS-CO 2 of AIST.

Regarding the geological storage of CO 2 in aquifers or in depleted gas fields, the reactivity of the well casing left in the abandoned well is important in order to investigate the potential for leakage. The corrosion behavior of the casing steel tube was investigated in highly pressurized CO 2 environments. The corrosion test of the J55 and N80 steel tube in API specification 5CT was conducted. Those steel tubes have been frequently used as casing tube and are found in abandoned natural gas wells. The following test conditions were achieved with the autoclave apparatus: temperature at 50 to 70 °C, CO 2 pressure at 5 to 18 MPa with/without the impurities of 20 ppm H 2 S and 2000 ppm CO, in/above stagnant 0.5 M NaCl solution of simulated formation water. The test durations were 100, 300 and 1000 hours. After the corrosion test, the specimens were analyzed by Energy dispersive X-ray spectrometry and X-ray diffractometry. The specimens were found to be covered mainly with FeCO 3 , which is considered to be formed from dissolved Fe 2+ and environmental CO 2 . The corrosion rate was evaluated via the weight loss of the specimens after the removal of the surface corrosion products, containing FeCO3. No significant differences were observed between J55 and N80 in terms of FeCO 3 formation and corrosion weight loss. It was found that the weight loss by corrosion, around 100 mg/cm 2 after 100 hours, was remarkably large when the specimen was placed in the solution and was, in contrast, two orders of magnitude smaller when the specimen was above the solution. In the case with the impurities of 20 ppm H2S and 2000 ppm CO, the weight loss in the solution was less relative to the pure CO 2 condition. The weight loss in the solution reached a plateau in initial 100 hours, and was only slightly increased in the 300- and the 1000-hour tests. The ‘plateau’ was considered to be due to the protective effect of the FeCO 3 formed on the specimen. Considering the protective effect of the FeCO 3 , the corrosion of the steel casing over a long period of time is small under the stagnant condition, and would be expected to remain in place with little structural degradation.

This paper reports logging results for well integrity conducted at the CO2 injection site in Japan. Well integrity is one of the essential issues for safety in geological CO2 storage. Wells in the Nagaoka site have been used for monitoring logging of CO2 behavior for more than ten years, and have experience of large earthquakes near the site. Time-lapse ultrasonic and cement bond logging have been employed to investigate the well integrity of the observation wells. Results of the ultrasonic logging showed that there was no sever damage or deformation in the casing at the reservoir depth. No clear change in cement can be seen in either logging results, even at the depth where the cement was exposed to the CO2. These results showed that there was no clear evidence of CO2 leakage at Nagaoka.

An abandoned well, completed without CO2 resistant materials, is thought to be a potential pathway for CO2 leakage to the surface. To examine the chemical impacts of a non-CO2 resistant well, we prepared composite samples consisting of J-55 casing material, Portland cement and sandstone (referred to as “simulated well sample”). Permeability of the simulated well sample decreased during a flow-through experiment using CO2-saturated brine. Precipitation of carbonate was found in both flow-through and batch experiments. The casing material was not degraded by CO2 if bonding between the casing and cement was tight. The sandstone surrounding the cement therefore seemed to act as a buffer medium against CO2 attack.

For a feasible risk assessment of CO2-leakage through wells of the carbon dioxide storage sites at abandoned wells of aquifers and depleted gas fields, the CO2 reactivity and permeability of casing steel, pseudo formation and cement- plug need to be evaluated experimentally as functions of temperature, pressure and formation water chemistry to provide fundamental information for the assessment. Two types of laboratory experiments were conducted. These experiments are shown below: (1) Conventional batch-reaction experiments of cement cores in the system of CO2 and simulated formation water as 0.5 M NaCl, at 50 and 70 C, 5, 8, 18 MPa for 100-1600hr. In this experiment, individual cement cores are allowed to react with wet CO2 and NaCl solution charged in titanium reaction vessels with PTFE separators. (2) CO2-injection reaction involving casing (API Grade J-55)-cement (API class A) and cement (API class A)-shale composites which were saturated with 0.5 M NaCl solution. As a counter experiment for batch experiments, zero CO2 runs for these cements were additionally carried out at 50 and 70 C at 5 MPa for 100 and 400 hr. The CO2-injection runs were carried out at 50 C and 8.5 MPa with a constant differential pressure of 5 kPa. The resultant products were used to analyze alteration depth via micro-focused X-ray computed tomography (-XCT) and electron probe micro analyzer (EPMA). For observation and determination of alteration phases, field mission scanning electron microscopy with energy dispersive spectroscopy (FESEM-EDS) and micro X-ray diffractometry (-XRD) were also performed. The alteration zones identified in the both cement cores of A and G in wet CO2 showed spatial developments of zones appearing in -XCT images as a function of square root of time (t1/2), which can be interpreted as a diffusion-limited reaction. However, in the NaCl solution, these cement cores developed little alteration zones and poorly displayed time-dependency after 100 h.

Poor wellbore integrity is a risk in CO2 storage that must be evaluated at any geologic sequestration site. The conditions of five wells from two fields in Wyoming were studied to better understand pre-injection leakage potential in existing wells. Ultrasonic and sonic logging tools mapped the condition of the casing and cement in each well. Permeability testing outside the casing was conducted using two different dynamic testing tools making point and vertical interference test measurements Permeability was also measured through laboratory testing of cased-hole sidewall cores. The results of laboratory measurements were generally in the microdarcy-to-nanodarcy range and indicate that the well cements have not degraded from exposure to the formation brines. The results of vertical interference tests when compared to lab measurements imply interfaces between casing and cement or cement and formation are more significant with respect to leakage than the quality of the cement at the tested location.

Samples of low alloyed steel AISI 4140 42CrMo4, used for casing, and stainless injection-pipe steel AISI 420 X46Cr13 as well as AISI 420J X20Cr13 were kept at T=60 °C and ambient pressure as well as p=100 bar for 700 h - 8000 h in a CO 2 -saturated synthetic aquifer environment similar to possible geological on-shore CCS-sites in the northern German Basin. Corrosion rates and scale growth are reduced at high pressure and pits -indicating local corrosion- decrease in diameter but increase in number as a function of exposure time.

The risk of leakage along existing wellbores associated with CO 2 sequestration depends strongly upon the leakage path permeabilities. If enough buildups of surface casing pressure (SCP) and rates of surface casing vent flow (SCVF) recorded on intermediate wellbore casing strings are available, a frequency distribution of leakage path permeability values can be obtained. Uncertainty about the location of the leak source results in a range of leakage path permeability values for each measurement of SCP or SCVF. Most permeability values exceed intact cement permeability, consistent with the presence of cracks or other defects in the formation/cement/casing interface. Assuming the gas migration path through leaky wellbores in hydrocarbon reservoirs is analogous to the leakage path for CO 2 plumes, the distribution of inferred permeabilities enables quantitative estimation of CO 2 leakage fluxes.

In the environment of HTHP and high H2S, the sour gas enters into the annulus as a result of various factors, leading to annulus pressure and inducing the risk of the stress corrosion cracking in the oil string or the upper casing. To solve the problem, the environmental fracture toughness of C110 high strength casing steel was tested in the NACE A solution and the wellbore protection fluid in simulated conditions in the CORTEST pressure testing system and homemade HTHP autoclave using NACE DCB method in this paper. Wellbore protection fluid is a corrosion inhibitor for steel in oil pipe and annulus. The results indicate that the environmental fracture toughness KISSC of C110 casing steel is 22.78 MPa•m1 / 2, showing strong environmental cracking sensitivity in the standard NACE A solution. In the wellbore protection fluid under the simulated down hole conditions, where the partial pressure of H2S is 1 MPa, the partial pressure of CO2 is 0.6 MPa, the total pressure is 48 Mpa and the temperature is 110°C, it has good resistance to stress corrosion cracking. It can be concluded that excellent wellbore protection fluid greatly increases the resistance of the material properties to environmental cracking. Research results in the paper provide a reference to the safe operation and management to the annulus pressure well in high sour gas fields.

Casing strength under the complex geological conditions is one of the major problems urgently to be solved at home and abroad. Catching the main characteristics and trends of casing collapse under the complex geological conditions, and based on which, carrying out the method study of casing strength analysis under the inhomogeneous load, as well as consideration of the law about how the non-uniformity load and the casing eccentricity influence on casing strength are of great significance. Setting a suit of method and theory about casing strength under the complex geological conditions has certain reference value. This paper affords a new sight for the casing strength design and safety assessment under the complex geological conditions by research on the relevance between the casing strength and the complex geological conditions. Meanwhile, consideration gives the non-uniformity load and the law about how the casing eccentricity influences on the casing strength. The results show that the increasing off-center distance will aggravate the non-uniformity of the loads when the casing skews along the relative off-center direction of 90° and 270°, thus the casing collapse risk goes up evidently.

High Temp PEM fuel cell technology is very well suited for technology CHP applications. The operating temperature is high enough for the integrated system with a matching reformer to produce high value heat, that can be used for district heating and hot water production. At the same time the high temperature polymer membranes, when operating in the range 160 to 200 degrees C, are very forgiving regarding CO content in the reformate, end this fact makes it possible to design and build a much simpler and cheaper reformer than I the cast for a conventional low temp PEM fuel cell system. However, until now very few robust designs have seen daylight, and the power density of HT PEM fuel cells has been very low. Metacon has developed a novel design, made to provide very high reliability and long life, at the same time as giving high power density. This novel design is founded in the understanding of the real operating conditions of such a fuel cell. It is easy to see that the conditions of a HT PEM fuel cell are very similar to those of an engine for a modern personal car: The temperature is cycled between ambient temperature and around 200 deg C, there are also pressure changes and stresses due to thermal expansion and temperature gradients during start- up and stop. The design developed and patented by Metacon is taking full consequences of these facts. The internal stack cooling is based on pressurized casing, high speed air circulation, and the external cooling uses circulating water, exactly as in a modern diesel engine.

Well integrity plays a key role in the overall performance of oil and gas projects, including Carbon Capture and Storage (CCS) projects. Well integrity has to be demonstrated over the well life-cycle, during operations (production, injection and/or monitoring), abandonment and few hundreds of years after closure, particularly to ensure effective CO2 confinement into the reservoir. To contribute to the development of CCS technologies at a commercial scale, a CO2 injection experiment was developed in Ketzin, Germany. The project included drilling three wells: one for CO2 injection, and two for CO2 monitoring. The COSMOS 2 R&D project included wellbore integrity evaluation through extensive modeling at a meso-scale (well components scale) and a macro scale (well scale). The modeling activities focused on the fluids migration from the reservoir along the wellbore taking into account ageing mechanisms (e.g. casing corrosion and cement leaching) and micro-annulus opening at cement/casing/rock interfaces due to thermo-mechanical stresses. Such modeling results have to be integrated in a pro-active risk-based management of well integrity in order to optimize design, define monitoring and maintenance action plan or demonstrate safety to authorities. The benefits are a good knowledge of the risks (causes and impacts), the assurance these are under control and, as a consequence, insurance of a secured investment.

Carbon dioxide (CO2) geological storage relies on safe, long-term injection of large quantities of CO2 in underground porous rocks. Wells, whether they are the conduit of the pumped fluid or are exposed to CO2 in the storage reservoir (observation and old wells) are man-made disturbances to the geological storage complex, and are thus viewed by some as a possible risk factor to the containment of the injected CO 2. Wells are composite structures, with an inner steel pipe separated from the borehole rock wall by a thin cement sheath (∼2 cm) that prevents vertical fluid migration. Both carbon steel and cement react in the presence of CO2, although evidence from production of CO2-rich fluids in the oil and gas industry and from lab experiments suggests that competent, defect-free cement offers an effective barrier to CO2 migration and leaks. However, reactivity of cement and steel may result in CO2 migration pathways degrading over time, thus in the leakage risk increasing during the life of the storage project. The issue then becomes how to best integrate preventive verification of zonal isolation/well integrity in the storage site monitoring plan. An analysis of the order of magnitude of possible CO2 leaks, and of their path to potable aquifers or the atmosphere, is also necessary to optimize the assurance (mitigation) monitoring of the storage site. Evidence gathered during the MovECBM project indicates that migration of small quantities of CO2 happened during injection in a coal seam in Southwest Poland. The evidence, gathered from casing and cement logging as well as soil gas monitoring over a 3-year period, was coupled with laboratory testing and extensive modeling of the chemo-mechanical behavior of cement and steel to determine if CO2 migration might have been responsible of the observed behavior. The three lines of evidence were: the detection of very small CO2 fluxes, coupled with less controversial helium concentration in soil; the occurrence of a thin pathway at the interface between cement and casing; and the change in mechanical properties of cement, suggestive of partial carbonation. Whereas the observations suggest that limited CO2 migration might have happened in the well, they are by no means proof that the migration did happen. Nonetheless, the integration of measurement and modeling yields important lessons for wellbore monitoring. First, it puts a probable ceiling on the order of magnitude of expected leaks from reasonably well-cemented wells at around 100 metric tons per year (less than 0.05% of the injected mass in a well like Sleipner or In Salah). It also suggests that cement may be a very effective leak detector: exposure to CO2 modifies its mechanical properties, which in turn can be detected using cement evaluation logs. Finally, coupling with dispersion modeling suggests the precision and accuracy required from soil gas and atmospheric monitoring, as well as the placement of sampling points; it also suggest that hysteresis, due to the accumulation in CO2 in surface aquifers and to the time required for it to be transported to the survey points, may delay initial detection; the same hysteresis may at the same time prolong the occurrence of CO2 shows long after the leak has stopped. © 2010 Elsevier Ltd. © 2011 Published by Elsevier Ltd.

When emission gasses are compressed into deep geological layers (CCS) CO 2 -corrosion of injection pipe steels is a relevant safety issue. The reliability of the steels used at the geological onshore CCS-site at Ketzin, Germany, is demonstrated in 2 years laboratory experiments under an equivalent corrosive environment at ambient pressure (T=60 °C, aquifer water, CO 2 -flow rate of 3 l/h). Corrosion kinetics and microstructures were characterized using samples of the heat treated steel 42CrMo4 (casing), and samples of the martensitic stainless steel X46Cr13 (injection).

Potential migration of CO 2 from subsurface reservoirs along wells is generally recognized as the major hazard associated with long-term storage of CO 2 in geological formations due to possible chemical and mechanical impact on wellbore cement or casing steel. Many storage projects involve the presence of pre-existing wellbores, penetrating the prospective storage container. Because of their inaccessibility, the main risk is associated with previously abandoned wells. The actual operations at the time of abandonment determine the suitability of these wells for future CO 2 storage operations. Past and present oil and gas well abandonment regulations, prescribing minimum requirements for the use of cement plugs to prevent inter-zonal communication, form a good proxy to assess the general status of abandoned wells. A high-level review of current abandonment regulations showed that required plug lengths vary greatly between different regions, from a minimum of 15 m in Alberta to 100 m in some European countries. Many experimental studies have been performed on degradation of wellbore cement under influence of aqueous CO 2 . Considering that diffusion of CO 2 in the cement matrix forms the rate-controlling step in cement degradation, extrapolation of the results of these studies shows that up to a few meters of cement may be affected in 10,000 years. In spite of the significant variation between the evaluated regulations, currently prescribed plug lengths seem appropriate for safe storage of CO 2 with respect to reported laboratory degradation rates. This implies that mechanical integrity of cement plugs and the quality of its placement probably is of more significance than chemical degradation of properly placed abandonment plugs.

An important aspect of the risk associated with geological carbon dioxide sequestration is the integrity of existing wellbores that penetrate geological layers targeted for CO 2 injection. CO 2 leakage may occur through multiple pathways along a wellbore within the “disturbed zone” surrounding the well casing. The disturbed zone is defined as the annular region along the exterior of the steel wellbore casing that includes the Portland cement sheath, the damage zone of the host rock and the casing-cement-rock interfaces. The effective permeability of this zone is a key parameter of wellbore integrity required for validation of numerical models. Effective permeability may depend on a number of complex factors, including long-term attack by aggressive fluids, poor well completion or actions related to production of fluids through the wellbore. Field tests are essential to understanding the in situ leakage properties of the millions of wells that exist in mature sedimentary basins in North America. We present results from recent field studies of different CO 2 producing wells from both natural CO 2 reservoirs and enhanced oil recovery (EOR) operations. These surveys have included a particular downhole pressure test, the vertical interference test (VIT), designed to determine the extent of hydraulic communication along the exterior of the well casing. The VIT test involves perforating the well casing in two separate intervals, both of which are located within the shale caprock and bracket a zone of cement identified to have a lower quality bond. Once the intervals are isolated with an inflatable packer, the system is pressurized from surface and held at a constant pressure, while simultaneously, the transient pressure response is measured in the lower isolated interval. The pressure transient data is an indicator of the extent of hydraulic communication and is the focus of subsequent analysis. The effective wellbore permeability can be determined through numerical analysis of the VIT data. Our objective is to identify to most effective method of analysis for estimating wellbore permeability. We evaluate two different automated parameter estimation methods, nonlinear regression and shuffled complex evolution metropolis methods. Within this study, we also estimate parameters such as permeability and compressibility of the low permeability shale zone to determine their effect on the resulting estimate of wellbore permeability. The results of this work demonstrate that parameter estimation can be effective at identifying the key parameters associated with wellbore integrity from VIT field tests, and ultimately reducing the uncertainty regarding the integrity of existing wellbores.

The concept of CO2 storage relies on the long-term sealing properties of both the geological trap and the wells needed to inject and monitor CO2. Well integrity, a classical topic in the oil and gas industry, is thus critical for the performance of any CO2 storage complex in terms of containment. Thanks to the very low permeability of cement (typically less than 0.1 mDarcy); a properly cemented well ensures hydraulic isolation between reservoirs layers and shallow aquifers. Moreover, such low matrix permeability limits the cement/ CO2 interactions over the active period of a storage complex (of the order of 100 years) to a few meters. Leaks from a cased and cemented well, if any, are known to occur only through defects: mud-channel (in case of poor cement placement), cracks within cement and more importantly micro-annulus at the casing/cement or/and cement/formation interfaces. This last category of defects can lead to substantial leakage rate. Its importance has been recognized by the oil and gas industry since the 1960's leading to the study of cement "bonding" properties. In the scope of CO2 storage, the understanding, modeling and monitoring of the occurrence of micro-annulus becomes of prime importance. We analyze the complete loading history of a cemented completion from cement placement to routine well operations. Further to classical failure type assessment used in the oil and gas industry (i.e. fail/no fail, good cement/bad cement), we aim at quantifying the vertical extent, azimuthal coverage and width of the created defects to adequately transform failure types into leakage pathways. Such a prediction of connected defects/leakage pathways along a cemented well imposes to consistently integrate the effects of lithology, geomechanics, cement placement (fluid loss, hydration), completion design and knowledge of pressure and thermal variation during the life of the well. The modeling of such a problem can be made tractable by recognizing the intrinsic hierarchy of lengthscales of a cemented well (i.e. the cement annulus is much thinner than the well dimension). The original three-dimensional problem is reduced to a much simpler two-dimensional one, which in turn can even be further reduced to a one-dimensional configuration in a lot of practical cases. Typical cases of interface debonding due to well de-pressurization and thermal cooling taking place after cement placement are carefully analyzed. Furthermore, we specially focus on injectors. Despite the use of all current best practices during well construction, the injection in itself can lead to the propagation of a debonding crack between cement and casing or cement and formation due to the high pressure generated at the perforations level. Such a problem has already been reported in hydraulic fracturing operations, and is a reasonable explanation of observed well leaks for injectors. A consistent model predicting the initiation and propagation of interface debonding during injection operations is then compared to carefully designed laboratory experiments. Such experiments also confirm that the azimuthal coverage of the interface debonding is only partial (i.e. less than 360°), an observation consistent with cement evaluation logs acquired on CO2 injectors. Finally, best practices to achieve and retain well integrity of CO2 injectors are highlighted from a careful examination of the results of both the model and the experiment. © 2011 Published by Elsevier Ltd.

Wellbore integrity is one of the key performance criteria in the geological storage of CO2. This 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 (create zonal isolation) wellbore systems. This work has emphasized the reactivity of Portland cement to form calcium carbonate. However, an increasing number of field studies [e.g., 1], experimental studies [e.g., 2], 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. The magnitude of flows along these interfaces is a complex function of the pressure gradient, geomechanical properties that support the interface and dissolution/precipitation reactions that lead to widening or closure of the interface. In this study, we investigate the casing-cement microannulus through core-flood experiments. The experiments were conducted on a 5-cm diameter sample of cement that was cured with an embedded rectangular length of steel casing. Prior to the experiment, the casing was loosened creating a poorly bonded interface. However, we discovered that under confining pressure this interface was non-transmissive, suggesting that in the wellbore environment an open casing-cement microannulus requires a relatively low differential between pore and confining pressure. For the experiments, we created an artificially transmissive interface by scoring grooves in the steel casing (0.2-0.8 mm in depth). The core-flood experiments were conducted at 40 ∘C, 14 MPa pore pressure, and 28 MPa confining pressure for a period of 400 hours. During the experiment, 6.2 L of a 50:50 mixture of supercritical CO2 and a 30,000 ppm NaCl-rich brine flowed through 10-cm of limestone before flowing through the 6-cm length cement-casing composite. Approximately 41,000 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 50–150 μm by a diffusion-dominated process. There was no evidence of mass loss or erosion of the Portland cement. By contrast, the steel casing reacted to form abundant precipitates of iron carbonate that lined the channels and in one case almost completed filled a channel. These results are compared to field studies to constrain the magnitude of possible CO2 migration in real wellbore systems.

This paper will present results of a numerical modelling study on CO2 migration through abandoned wells. Leakage of CO2 through plugged and abandoned wellbores is one of the major concerns for long-term safety and effectiveness of geologic CO2 sequestration. For risk assessment and mitigation, it is not only important to understand and characterize the potential for CO2 leakage through wellbores but also subsequent CO2 migration beyond the primary sequestration reservoir. Subsequent to the leak, CO2 may take a direct path towards the accessible environment or it may migrate in an indirect stair-stepping manner through wellbores/fractures across multiple, shallow permeable strata. In the later case, identification of leak source and application of mitigation strategies may become a challenge.For this study we use data from a site in Alberta, Canada which has reported natural gas leak at surface. Investigations on origin of the gas and potential gas migration path from the original source to the surface at the analog site show that the gas could be moving through multiple wells and across multiple formations. There are multiple wells at the site which were drilled and abandoned without production casing and are completely open between two hydrocarbon bearing zones creating cross-flow across zones through open wellbores. Our study focuses on the deeper formations and potential for leakage for CO2 injected in deeper formation. A complex numerical fluid-flow model is developed for the site in FEHM, LANL’s porous media fluid-flow simulator. The model explicitly accounts for wellbore details such as abandonment plugs, casing, annulus cement, etc. The model was used to perform long-term simulations of CO2 injection and potential migration through abandoned wells. Numerical simulation results show limited migration of CO2 through abandoned wells. Such detailed simulation would be valuable to develop effective abandonment practices as well as mitigation strategies at CO2 sequestration sites.

Wells are designed to bring fluids from depth to the earth’s surface quickly. As such they are the most likely pathway for CO2 to return to the surface in large quantities and present a hazard without adequate management. We surveyed oil industry experience of CO2 well failures, and separately, calculated the maximal CO2 flow rate from a 5000 ft depth supercritical CO2 reservoir. The calculated maximum of 20,000 tonne/day was set by the sound speed and the seven-inch well casing diameter, and was greater than any observed event. We used this flux to simulate atmospheric releases and the associated hazard utilizing the National Atmospheric Release Advisory Center (NARAC) tools and real meteorology at a representative location in the High Plains of the United States. Three cases representing a maximum hazard day (quiet winds

CO2-corrosion of injection pipe steels is a relevant safety issue when emission gasses are compressed in deep geological layers (CCS). The reliability of the steels used at the geological onshore CCS-site at Ketzin, Germany, is demonstrated in laboratory experiments under an equivalent corrosive environment (T=60 ∘C,p=1−60 bar, aquifer water, CO2-flow rate of 3 l/h, 700 h–8000 h heat treatment). Corrosion kinetics and microstructures were characterized using samples of the heat treated steel 1.7225 (AISI 4140, 42CrMo4) used for casing, and samples of the martensitic stainless injection-pipe steel 1.4034 (AISI 420, X46Cr13).

Wells have been identified as posing a greater risk for leakage from CO2 storage sites than geological features such as faults and fractures, particularly in mature sedimentary basins with high well density such as those onshore in North America. A commonly-held belief is that CO2 injection wells will pose a lesser risk than wells drilled for other purposes because greater care would be taken in regard to their completion and operation. The existence of CO2 and acid gas injection operations in Alberta, Canada, provided the opportunity to test this hypothesis. Currently in Alberta there are 31 wells used for CO2 injection and 48 wells used for the disposal of produced acid gas (a mixture of CO2 and H2S that is separated from sour gas to meet pipeline and market specifications). Only 22 wells were drilled specifically with the purpose of injecting CO2 or acid gas; all others are previous wells that have been subsequently converted to injection wells. Well failures include: surface casing vent flow, casing failure, tubing failure, packer failure, and zonal isolation failure. The incidence of well failure is greater in the case of converted wells than in the case of wells drilled and completed for injection purposes. Most failures are not caused by injection; they are due to general causes encountered in the general well population. Failures due to injection are mostly tubing and packer failures, which are monitored by regulation and are easily detected and repaired. The incidence of well failure is greater for wells drilled prior to the advent of regulations in 1994 regarding drilling and completion of injection wells. While the incidence of failure in the CO2 and acid gas injection wells in Alberta is comparable to that in the general well population, the analysis indicates that injection wells drilled for purpose and under a proper regulatory regime have a lesser incidence of failure than the general well population. A proper regulatory framework for CO2 injection wells is essential for reducing and preventing well failures.

A hypothetical CO 2 storage site that has some abandoned wells located near the injection well is considered. Generally, cement plugs are set to cover or isolate porous or productive formations and to isolate usable groundwater from hydrocarbons. When CO 2 is injected into a reservoir, supercritical CO 2 or dissolved CO 2 spreads out in the reservoir. This dissolved CO 2 can react chemically with cement seals (plugs and casing cement) in abandoned wells. As a result, minerals in the cement seals (plugs and casing cement) may alter to form other minerals or mineral phases. The first simulations concerning migration of supercritical CO 2 and dissolved CO 2 in a saline aquifer and a depleted gas field reservoir, were carried out using TOUGH2. The following temperatures and depths of reservoir were selected: 50 °C at E.L.-1,000 m, 60 °C at E.L.-1,500 m and 70 °C at E.L.-2,000 m. Secondly, geochemical reactions of cement seals (plugs and casing cement) were simulated. The results of reservoir simulations were used as boundary conditions for the geochemical calculation of cement seals. Geochemical simulation of the reactions yielded the extent (length) of alteration of cement seals (plugs and casing cement) after long time periods; for example, the alteration length of cement seals after 1,000 years was about one meter. This length is short enough so that the usable cement seals (plugs and casing cement) of abandoned well are able to continue to isolate CO 2 in the reservoir from the upper aquifer.

The Rousse field, located in the Lacq basin in the southwest of France, is a site for a pilot carbon dioxide (CO2) storage project operated by Total. Since 2010, CO2 has been injected into a depleted gas field at a depth of 4.5 km through RSE-1, a 45-year old production well converted to an injection well. Older wells are commonly recognized as the most likely pathway for CO2 to migrate from the injection zone to other zones or to the surface. A number of factors could increase the potential risk for these wells: completions and production history may have created defects in the sealing elements (cement, steel and elastomers); the history itself may not be known in sufficient detail to estimate a reliable risk figure and finally the injected or produced fluids may have corroded the structure. Old wells, whether they are converted to injectors or are in the path of the injection pressure field, could require renewed evaluation and preventive repairs as part of the field-level containment management plan, if their integrity assessment request so. As part of the due diligence process, advanced cement and steel evaluation logging tools were run in the RSE-1 well to investigate the bottom kilometer of the two kilometer-thick caprock. The 3D integrity map produced by the acoustic logging tools was analyzed for the presence of connected defects (pathways) that could lead to unwanted CO2 migration. The logs were also compared to the original 40 year old low-resolution sonic log to assess the extent of degradation, if any. A particular issue for wells drilled before the 1990's, when technological advances almost eliminated the problem, is that of mud channels left behind during the cement placement process. These defects present the highest risk because of their relatively large flow area. Since the well was completed in 1967, special attention was paid to the occurrence, connectivity and extent of channels. Even though imaging of the cemented annulus revealed an eccentered casing, almost lying on the rock face, and an oval borehole, the few mud pockets trapped between casing and rock were confirmed to be intermittent, with good cement providing hydraulic isolation between them. The comparison of the through-casing caliper to the formation sonic log enabled identification of borehole breakouts, caused by stress

A quantitative risk assessment method of casing collapse resistance and internal pressure resistance is established in accordance with the theory of structural reliability and random theory, in terms of geometrical parameters, mechanical property and external load randomness of casing and on the basis of the analysis on shortcomings of safety coefficient and assessment methods for conventional casing design. Using Monte-Carlo random sampling method, a probability of casing failure with different pressure and a relationship between safety coefficient and probability of casing failure have been obtained by simulating a random distribution regularity of casing strength. Studies show that quantitative risk assessment methods could be adopted to perform quantitative assessment on casing safety and reliability. Casings of different types and under the effect of different external loads have similar safety coefficient and different probabilities of failure. Failure probability assessment index calculated with random theory may provide bases for the selection of conventional safety coefficient and casing design and assessment with uncertain external loads.

Chemical interaction of Portland cement with supercritical CO2 along the cement - sandstone interface was investigated. To model a well in a CO2 geological storage site, we prepared the well composite sample consisting of casing, Portland cement and sandstone. Using this sample, we conducted batch experiments in a laboratory scale to estimate the chemical interactions of CO2 under a reservoir condition (10 MPa, 50 °C, 0.5 M NaCl). The elemental and crystal phase analysis of CO2 exposed samples were carried out by SEM-EDS and μ-XRD. In the cement region, a carbonation zone of the cement occurred adjacent to the sandstone with both samples exposed to CO2. From the results of SEM-EDS analysis, it was found that Ca concentration in the carbonation zone increased about 20% in comparison to that in the unaltered cement zone while concentration of Mg, Si, S at the carbonation zone decreased. Crystal phase at the carbonation zone were predominantly CaCO3 (calcite, aragonite and vaterite) and trace Friedel's salt. In addition, CaCO3 were sparsely precipitated in the pore spaces of sandstone along the sandstone-cement interface. These results indicate that the formation of carbonation layer provides as an effective barrier to further CO2 attack.

Annular cementing is an essential step in well construction in underground CO 2 storage projects. The quality of cementing depends on the quality of mud displacement by the fluids injected into the annulus during the cementing job. An engineering numerical model of annular fluid displacement in a vertical well was used in this study to investigate the effect of well profile on the displacement quality. Annular displacement of the thinner fluid in place by the injected thicker fluid was modelled. The effect of the following factors on the displacement was studied: slightly irregular shape of the well cross-section; eccentric positioning of the casing in a circular well; a local washout (enlargement of the well cross-section); throughgoing breakouts. Random irregularities of the well cross-section were found to have only a minor effect on the advancement of the displacement front and on the injection pressure. Eccentric positioning of the casing pipe was found to cause flow channelization due to the yield-stress rheology of the fluids. The eccentricity was found to affect the injection pressure as well. An isolated washout was found to have only a minor influence on the injection pressure and the displacement front propagation. Borehole breakouts were found to cause severe channelization of the injected fluid, and a substantial reduction in the injection pressure. Continuous enlargements of the annulus caused e.g. by borehole breakouts or eccentric positioning of the casing were thus shown to have a more detrimental effect on the annular displacement than a local, isolated enlargement caused e.g. by a washout. Abnormally low injection pressure during a cementing job might serve as an indication of flow channelization through such a throughgoing enlargement.

The Southeast Regional Carbon Sequestration Partnership (SECARB) early project in western Mississippi has been testing monitoring tools and approaches to document storage efficiency and storage permanence under conditions of CO2 EOR as well as downdip injection into brine. Denbury Onshore LLC is host for the study and has brought a depleted oil and gas reservoir, Cranfield Field, under CO2 flood. Injection was started in July 2008 and has now achieved injection rates greater than 1.2 million tons/year though 23 wells, with cumulative mass injected as of August, 2010 of 2.2 million metric tons. Injection is into coarse grained fluvial deposits of the Cretaceous lower Tuscaloosa Formation in a gentle anticline at depths of 3300 m. A team of researchers from 10 institutions has collected data from five study areas, each with a different goal and different spatial and temporal scale. The Phase 2 study began at the start of injection and has been using pressure and temperature as a tool for assessing permanence mostly in the oil productive interval. Real-time read-out shows high sensitivity to distant changes in injection rate and confirms the geologic model of reservoir compartmentalization. Above-zone pressure monitoring ∼120 m above the injection interval is used to test the sensitivity of this approach for documentation of integrity of the confining system in an area of numerous well completions as pressure increase is induced in the reservoir by more than 70 bar. Monitoring of the High Volume Injection Test (HiVIT) area includes repeat measurements of aqueous geochemistry in the injection zone. Rock-water- CO2 interactions in the reservoir as CO2 dissolves are minimized by mineral “armoring” by abundant chlorite cement in high permeability reservoir sandstone. Geochemical monitoring of confined freshwater aquifers at depths of 70–100 m is underway. Groundwater analysis focuses on assessment of the sensitivity of this method to detect leakage above background variability. A repeat seismic survey of the HiVIT is planned for late 2010 to assess saturation change especially in downdip brine-only areas. A study focused on feasibility of monitoring the shallow subsurface to separate leakage from normal complex surface fluxes is underway at an monitoring array installed in October 2009 to assess the interactions of recharge, soil gas, and shallow groundwater aquifers. Recent well re-entry and tracer injection will provide further information to interpret observed elevated deep-sourced methane. The Detailed Area Study (DAS) is collecting dense time-lapse data from closely-spaced three well array of an injector and two observation wells. The observation wells were completed with fiberglass casing to facilitate electrical resistance tomography (ERT) measurements, and a diverse array of instrumentation was both cemented behind casing and suspended on tubing. Injection started at the DAS December 1, 2009. We have measured pulsed neutron and resistivity via wireline, downhole and above-zone pressure, distributed temperature, and fluid chemistry including introduced pulses of perfluorocarbons, noble gases, and SF6 as tracers. Between wells, time-lapse crosswell seismic and electrical resistance tomography (ERT) are used to measure saturation change. The goals are to measure changes as fluids evolve from single phase (brine) to two phase (CO2–brine) in order to document linkages between pressure and sweep efficiency. A time-lapse VSP survey bridges the vertical resolution and areal coverage between cross-well and surface seismic. The repeat surveys for many tools are scheduled for September, 2010. Reservoir characterization based on cores, historic and new wireline log data, production history, hydrologic tests, fluid analysis, and a three-D seismic survey have been used in multiple numerical models to predict reservoir response in order to design effective monitoring strategies and optimize deployment. History matching of observed response to predicted response is used to interpret results and improve confidence in conceptual models and numerical approaches. Probabilistic methods have been used to assess the significant uncertainties resulting from reservoir heterogeneity. This study is funded by the US Department of Energy, National Energy Technology Laboratory as part of the Regional Carbon Sequestration Partnerships program. SECARB is led by Southern States Energy Board.

Wells drilled through low-permeable caprock are potential connections between the CO2 storage reservoir and overlying sensitive targets like aquifers and targets located at the surface. The wellbore integrity can be compromised due to in situ operations, including drilling, completion, operations and abandonment or to geochemical degradation of the caprock-cement-casing system. We present here an experimental set-up in the underground rock laboratory of Mont-Terri (St Ursanne, canton of Jura, Switzerland): the drilling and well completion in the laboratory will be done in the aim of reconstructing interfaces between the caprock, the cement and the casing steel that would be close to the ones observed in situ. These well features will then be dipped within a CO2 stream, during a given time period before a final over-coring. Such an experiment should provide new insights on the quality of bounding between casing/cement/clay interfaces and its evolution due to geochemical reactions. In parallel, a modeling effort is performed focused on both geochemical and transport aspects of the interactions between the fluids and the well compartments.