Academic literature on the topic 'Injectivité du CO2'
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Journal articles on the topic "Injectivité du CO2"
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Sokama-Neuyam, Yen Adams, Jann Rune Ursin, and Patrick Boakye. "Experimental Investigation of the Mechanisms of Salt Precipitation during CO2 Injection in Sandstone." C 5, no. 1 (2019): 4. http://dx.doi.org/10.3390/c5010004.
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Deep saline reservoirs have the highest volumetric CO2 storage potential, but drying and salt precipitation during CO2 injection could severely impair CO2 injectivity. The physical mechanisms and impact of salt precipitation, especially in the injection area, is still not fully understood. Core-flood experiments were conducted to investigate the mechanisms of external and internal salt precipitation in sandstone rocks. CO2 Low Salinity Alternating Gas (CO2-LSWAG) injection as a potential mitigation technique to reduce injectivity impairment induced by salt precipitation was also studied. We found that poor sweep and high brine salinity could increase salt deposition on the surface of the injection area. The results also indicate that the amount of salt precipitated in the dry-out zone does not change significantly during the drying process, as large portion of the precipitated salt accumulate in the injection vicinity. However, the distribution of salt in the dry-out zone was found to change markedly when more CO2 was injected after salt precipitation. This suggests that CO2 injectivity impairment induced by salt precipitation is probably dynamic rather than a static process. It was also found that CO2-LSWAG could improve CO2 injectivity after salt precipitation. However, below a critical diluent brine salinity, CO2-LSWAG did not improve injectivity. These findings provide vital understanding of core-scale physical mechanisms of the impact of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be implemented in simulation models to improve the quantification of injectivity losses during CO2 injection into saline sandstone reservoirs.
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Guo, Boyun, and Peng Zhang. "Injectivity Assessment of Radial-Lateral Wells for CO2 Storage in Marine Gas Hydrate Reservoirs." Energies 16, no. 24 (2023): 7987. http://dx.doi.org/10.3390/en16247987.
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The carbon dioxide (CO2) leak from conventional underground carbon storage reservoirs is an increasing concern. It is highly desirable to inject CO2 into low-temperature reservoirs so that CO2 can be locked inside the reservoir in a solid state as CO2 hydrates. Marine gas hydrate reservoirs and surrounding water aquifers are attractive candidates for this purpose. However, the nature of the low permeability of these marine sediments hinders the injection of CO2 on a commercial scale due to the low injectivity of wells with conventional completions. This study investigates the injection of CO2 into low-permeability marine reservoirs through a new type of well, namely a radial-lateral well (RLW). A mathematical model was developed in this study to predict the CO2 injectivity of the RLW. The model comparison shows that the use of RLW to replace vertical wells can improve CO2 injectivity by over 30 times, and the use of RLW to replace frac-packed wells can increase CO2 injectivity by over 10 times. A case study and sensitivity analysis were performed with field data from the South China Sea. The result of the analysis reveals that the injectivity of the RLW is nearly proportional to reservoir permeability, lateral wellbore length, and the number of laterals. The CO2 injection rate is predicted to be 19 tons/day to 250 tons/day, which is 3 to 15 times higher than the injectivity of frac-packed wells. It is feasible to inject CO2 into the low-permeability, low-temperature marine reservoirs at commercial flow rates. This work provides an analytical tool to predict the CO2 injectivity of RLW in low-temperature marine reservoirs for leak-free CO2 storage.
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Carpenter, Chris. "CO2 Injectivity Test Proves Concept of CCUS Field Development." Journal of Petroleum Technology 76, no. 02 (2024): 63–65. http://dx.doi.org/10.2118/0224-0063-jpt.
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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.
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Rogers, John D., and Reid B. Grigg. "A Literature Analysis of the WAG Injectivity Abnormalities in the CO2 Process." SPE Reservoir Evaluation & Engineering 4, no. 05 (2001): 375–86. http://dx.doi.org/10.2118/73830-pa.
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Summary This paper summarizes the hypotheses and theories relating to the causes and expectations of injectivity behavior in various CO2 and gasflooded reservoirs. The intent of the paper is to:Provide a concise compendium to the current understanding of the water-alternating-gas (WAG) mechanism and predictability.Provide a comprehensive single-source review of the causes and conditions of injectivity abnormalities in CO2/gasflood EOR projects.Aid in formulating the direction of research.Help operators develop operational and design strategies for current and future projects, as well as to input parameters for simulating current and future projects. Background Moritis1 identified 94 gas improved oil recovery (IOR) projects in the U.S. Of these, 74 are still active and 64 are CO2 miscible projects. New CO2 projects start each year. Five new U.S. miscible CO2 projects were being planned as of January 2000. Brock and Bryan2 presented a summary of CO2 IOR projects and reviewed the performance of 30 full-scale field projects and field pilots up to 1987. In 1992, there were 45 active CO2 projects in the U.S.3 Because of the low oil prices following the 1985-86 price collapse, the initial industry outlook was pessimistic; however, by 1992, most projects had been shown to be technically and economically successful. In a number of projects, the production performance has been better than anticipated.3 At the beginning of 2000, and based on 1999 production figures, the U.S. production from gas-injected IOR was estimated at 328,759 B/D, or approximately 5% of the total oil production in the U.S. Oil production from CO2 activity alone contributed 189,493 B/D, which is an increase of 5.8% over 1998 production attributable to CO2 production and represents 3% of the 1999 U.S. oil production.1 This increase occurred despite the 1998-99 price collapse, which was deeper than the mid-1980s collapse. The Permian Basin of west Texas and southeastern New Mexico remains a very active area for CO2 projects. However, CO2 IOR field or pilot projects also exist in seven other states: California, Colorado, Kansas, Michigan, Mississippi, Oklahoma, and Utah. Analysis of individual projects4 and reported problems are not presented here. A review of 23 projects regarding injectivity is included in a U.S. Dept. of Energy annual report.5 A number of reviews have appeared in the literature.1-3,4,6 During the spring of even years, the Oil & Gas Journal usually publishes a survey of active IOR projects. Industry's Initial Concerns. There are two basic IOR techniques in gasflooding a reservoir-continuous gas injection and the WAG injection scheme. Industry initially had a number of concerns about CO2 injection, especially during the WAG process, in terms of controlling the higher-mobility gas: water blocking, corrosion, production concerns, oil recovery, and loss of injectivity. Careful planning and design along with good management practices have allayed most concerns, except for loss of injectivity. Lower injection rates of CO2 slugs and water slugs have been a concern because CO2 field tests were conducted in the early 1970s.7 Currently, the problem is still a concern in the management of a WAG process.4 This concern is the primary focus of this paper. Injectivity Losses. There are two separate but related questions regarding this perplexing issue.What causes the unexpectedly low injectivity during gas injection?What is the reason for the apparent reduction in water injectivity during brine injection after gas injection? Injectivity is a key variable for determining the viability of a CO2 project. Potential loss of injectivity and corresponding loss of reservoir pressure (and possibly loss of miscibility resulting in lower oil recovery) have potentially major impacts on the economics of a gas-injection process. Many of the projects evaluated by Hadlow3 showed higher CO2 (gas) injectivity than that obtained in prewaterflood water injection. However, substantial loss in water injectivity after CO2 or gas injection also has been seen. On the average, an approximately 20% loss of water injectivity can be expected in the WAG process3; attempts to mitigate this include decreasing the WAG ratio to decrease the mobility control, increasing the injection pressure, and adding additional injection wells. Optimization of operations can improve the economics of existing CO28 and other enhanced oil recovery (EOR) projects significantly. Three major management parameters that effect the economics of a CO2 or gasflood are:8The CO2 and water half-cycle slug sizes.The gas/water ratio profile.The ultimate injected CO2 slug size. Overview of WAG Injection Process WAG Process Description. The WAG scheme is a combination of two traditional techniques of improved hydrocarbon recovery: waterflooding and gas injection.9 The first field application of WAG is attributed to the North Pembina field in Alberta, Canada, by Mobil in 1957,6 where no injectivity abnormalities were reported. Conventional gas or waterfloods usually leave at least 50% of the oil as residual.10 Laboratory models conducted early in the history of flooding showed that simultaneous water/gas injection had sweep efficiency as high as 90%, compared to 60%10 for gas alone. However, completion costs, complexity in operations, and gravity segregation from simultaneous water/gas injection indicated that it was an impractical method for minimizing mobility. Therefore, a CO2 slug followed by WAG has been adopted. The planned WAG ratios of 0.5:4 in frequencies of 0.1 to 2% PV slugs of each fluid11 will cause water-saturation increases during the water cycles and decreasing water saturations during the gas half of the WAG cycle. The displacement mechanism caused by the WAG process occurs in a three-phase regime; the cyclic nature of the process creates a combination of imbibition and drainage.9 Optimum conditions of oil displacement by WAG processes are achieved if the gas and water have equal velocity in the reservoir. The optimum WAG design is different for each reservoir and needs to be determined for a specific reservoir and possibly fine-tuned for patterns within the reservoir.12 There are a number of different WAG schemes to optimize recovery. Unocal patented a process called Hybrid-WAG, in which a large fraction of the pore volume of CO2 to be injected is injected followed by the remaining fraction divided into 1:1 WAG ratios.11 Shell empirically evolved a similar process called DUWAG (Denver Unit WAG) by comparing continuous injection and WAG processes.
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Ganesh, Priya Ravi, and Srikanta Mishra. "Reduced Physics Modeling of CO2 Injectivity." Energy Procedia 63 (2014): 3116–25. http://dx.doi.org/10.1016/j.egypro.2014.11.336.
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Gasda, Sarah, and Roman Berenblyum. "Intermittent CO2 injection: injectivity and capacity." Baltic Carbon Forum 2 (October 13, 2023): 18–19. http://dx.doi.org/10.21595/bcf.2023.23643.
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Сarbon capture and storage (CCS), especially offshore, involves a chain of complex and expensive infrastructure connecting emitters to the disposal site. The classic example of an industrial cluster sending CO2 by a large pipeline to a nearby storage site is considered the most favorable solution in term of techno-economics. However, many emitters are located either too far from suitable offshore geology or are dispersed in harder to reach locations, making pipeline transport uneconomical. In these instances, ship transport is a viable option for shuttling CO2 from source to sink. The Northern Lights project in Norway will implement this approach, using shuttle tankers to deliver CO2 to an onshore receiving terminal. One should note that onshore terminals add significant cost to CCS, and their permanence can hinder flexibility and delay future expansion to new regions. High costs can also hinder small emitters to embark on CCS journey until the larger infrastructure is in place and the price for joining the value chain drops. Direct injection from ships can be a good supplement to the offshore transport portfolio, allowing ships to offload CO2 directly to the injection well on a periodic basis. While direct ship injection introduces a planned intermittency into the CCS chain, intermittency can also be caused by planned maintenance and technical issues along the value chain; energy supply and demand (where either less emissions are available due to, for example, higher renewables production or less energy is available for injection, in, for example, offshore renewable energy driven case); seasonal variations (part of CO2 used in agriculture or seasonal variation of injection temperature). The effect of intermittency, in general, is not fully understood. Part 1: aspects of intermittency on the storage reservoirLittle is known about the impact of injectivity CO2 injection on storage performance, i.e. injectivity and capacity. Recent studies indicate that cycling injection can delay bottom-hole pressure build-up, thus increasing capacity of the reservoir. On the other hand, evidence from field tests show that pressure relief can cause dissolved CO2 to exsolve into bubbles that block pores and reduce injectivity. Salt precipitation is another aspect that can be either positively or negatively impacted by flow cycling. In this case, repeated drainage-imbibition cycles may dissolve salt crystals formed in a previous cycle, improving injectivity, or it may continue to feed the system with new saltwater, thus impairing injectivity. The topic of salt precipitation is an active area of research.Part 2: how to deal with itWe present results of the recent study down for NEMO Maritime AS in a research council of Norway sponsored NEMO project. The talk will briefly highlight simulation outcomes on the near wellbore and field scale.Part 3: where do we go from hereFinally, we shortly introduce a recently funded CTS project which will focus on several aspects of direct injection from ships, including full-chain LCA/TEA based on Strategy CCUS H2020 project approach and scenarios. The project focuses on four different regions of Europe, including Baltics.
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Gong, Jiakun, Yuan Wang, Raj Deo Tewari, Ridhwan-Zhafri B. Kamarul Bahrim, and William Rossen. "Effect of Gas Composition on Surfactant Injectivity in a Surfactant-Alternating-Gas Foam Process." Molecules 29, no. 1 (2023): 100. http://dx.doi.org/10.3390/molecules29010100.
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Aqueous foam is a dispersion of gas in liquid, where the liquid acts as the continuous phase and the gas is separated by thin liquid films stabilized by a surfactant. Foam injection is a widely used technique in various applications, including CO2 sequestration, enhanced oil recovery, soil remediation, etc. Surfactant-alternating-gas (SAG) is a preferred approach for foam injection, and injectivity plays a vital role in determining the efficiency of the SAG process. Different gases can be applied depending on the process requirements and availability. However, the underlying mechanisms by which gas composition impacts injectivity are not yet fully understood. In this work, the effect of gas composition on fluid behavior and injectivity in a SAG process was investigated using three gases: N2, CO2, and Kr. Our observations revealed that gas solubility in liquid was key for the formation and evolution of liquid fingers, and therefore was very important for liquid injectivity. A lower gas solubility in liquid led to a slower increase in surfactant solution injectivity. In addition, the development of surfactant solution injectivity took significantly longer when the surfactant solution was partially pre-saturated compared to when it was unsaturated. Additionally, the propagation of the collapsed-foam bank during gas injection was accelerated when the gas had a greater solubility in water.
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Heidarabad, Reyhaneh Ghorbani, and Kyuchul Shin. "Carbon Capture and Storage in Depleted Oil and Gas Reservoirs: The Viewpoint of Wellbore Injectivity." Energies 17, no. 5 (2024): 1201. http://dx.doi.org/10.3390/en17051201.
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Recently, there has been a growing interest in utilizing depleted gas and oil reservoirs for carbon capture and storage. This interest arises from the fact that numerous reservoirs have either been depleted or necessitate enhanced oil and gas recovery (EOR/EGR). The sequestration of CO2 in subsurface repositories emerges as a highly effective approach for achieving carbon neutrality. This process serves a dual purpose by facilitating EOR/EGR, thereby aiding in the retrieval of residual oil and gas, and concurrently ensuring the secure and permanent storage of CO2 without the risk of leakage. Injectivity is defined as the fluid’s ability to be introduced into the reservoir without causing rock fracturing. This research aimed to fill the gap in carbon capture and storage (CCS) literature by examining the limited consideration of injectivity, specifically in depleted underground reservoirs. It reviewed critical factors that impact the injectivity of CO2 and also some field case data in such reservoirs.
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Ziaudin Ahamed, M. Nabil, Muhammad Azfar Mohamed, M. Aslam Md Yusof, Iqmal Irshad, Nur Asyraf Md Akhir, and Noorzamzarina Sulaiman. "Modeling the Combined Effect of Salt Precipitation and Fines Migration on CO2 Injectivity Changes in Sandstone Formation." Journal of Petroleum and Geothermal Technology 2, no. 2 (2021): 55. http://dx.doi.org/10.31315/jpgt.v2i2.5421.
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Carbon dioxide, CO2 emissions have risen precipitously over the last century, wreaking havoc on the atmosphere. Carbon Capture and Sequestration (CCS) techniques are being used to inject as much CO2 as possible and meet emission reduction targets with the fewest number of wells possible for economic reasons. However, CO2 injectivity is being reduced in sandstone formations due to significant CO2-brine-rock interactions in the form of salt precipitation and fines migration. The purpose of this project is to develop a regression model using linear regression and neural networks to correlate the combined effect of fines migration and salt precipitation on CO2 injectivity as a function of injection flow rates, brine salinities, particle sizes, and particle concentrations. Statistical analysis demonstrates that the neural network model has a reliable fit of 0.9882 in R Square and could be used to accurately predict the permeability changes expected during CO2 injection in sandstones.
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Yu, Shuman, and Shun Uchida. "Geomechanical effects of carbon sequestration as CO2 hydrates and CO2-N2 hydrates on host submarine sediments." E3S Web of Conferences 205 (2020): 11003. http://dx.doi.org/10.1051/e3sconf/202020511003.
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Over the past 10 years, more than 300 trillion kg of carbon dioxide (CO2) have been emitted into the atmosphere, deemed responsible for climate change. The capture and storage of CO2 has been therefore attracting research interests globally. CO2 injection in submarine sediments can provide a way of CO2 sequestration as solid hydrates in sediments by reacting with pore water. However, CO2 hydrate formation may occur relatively fast, resulting decreasing CO2 injectivity. In response, nitrogen (N2) addition has been suggested to prevent potential blockage through slower CO2-N2 hydrate formation process. Although there have been studies to explore this technique in methane hydrate recovery, little attention is paid to CO2 storage efficiency and geomechanical responses of host marine sediments. To better understand carbon sequestration efficiency via hydrate formation and related sediment geomechanical behaviour, this study presents numerical simulations for single well injection of pure CO2 and CO2-N2 mixture into submarine sediments. The results show that CO2-N2 mixture injection improves the efficiency of CO2 storage while maintaining relatively small deformation, which highlights the importance of injectivity and hydrate formation rate for CO2 storage as solid hydrates in submarine sediments.
Dissertations / Theses on the topic "Injectivité du CO2"
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Issautier, Benoit. "Impact des hétérogénéités sédimentaires sur le stockage géologique du CO2." Thesis, Aix-Marseille 1, 2011. http://www.theses.fr/2011AIX10136.
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La démarche d’intégration des hétérogénéités dans les modèles réservoirs en est à ses prémices dans le domaine du stockage géologique de CO2. C’est dans ce contexte que s’inscrivent ces travaux de thèse. Un protocole d’analyse depuis l’étude de terrain jusqu’aux simulations réservoirs a été établi. La caractérisation du Minjur Sandstone (formation Triasique d’Arabie Centrale) met en avant le caractère crucial de la connectivité des corps dans l’architecture du réservoir, notamment en liant génétiquement leur nature, leur connectivité et leur position dans la séquence de dépôt. S’appuyant sur la connaissance de cette formation, un modèle conceptuel est construit, puis reproduit stochastiquement par un algorithme permettant l’élaboration de modèles conditionnés par une histoire sédimentaire. Le protocole prévoit la création de 50 scénarios illustrant divers degrés de connectivité ; chaque scénario étant composé de deux modèles de même architecture mais à remplissage sédimentaire différent. Cette approche permet d’appréhender (a) l’impact de la connectivité et (b) des hétérogénéités sédimentaires sur les performances réservoirs. L’estimation de capacité par l’approche statique des volumes disponibles estime une capacité moyenne d’environ 13Mt (aquifère semi-infini de 25 km par 25 km et 60m d’épaisseur à 1000 m de profondeur). Les hétérogénéités internes (sédiments argileux appelés oxbow lakes) entraînent une différence de capacité de 30%. Les simulations dynamiques confirment ces résultats et révèle une variabilité de capacité de 23% liée la connectivité des corps. De plus les hétérogénéités réduisent la migration verticale du gaz ce qui peut augmenter l’intégrité du stockage<br>In the CO2 storage context, heterogeneity has only been rarely considered in reservoir models to date. To address this key issue, the project aims at developing a workflow that manages the heterogeneity from the field observations up to the reservoir simulation. The characterisation of the Minjur Sandstone (a Triassic formation from Central Saudi Arabia) shows the crucial role of connectivity in the reservoir architecture, and the genetic link between the nature, location and connectivity of the sedimentary bodies in the sequence. Stemming from this study, a conceptual model was established and stochastically reproduced through an algorithm simulating models conditioned to a sedimentary history. Fifty scenarios were simulated, representing various connectivity degrees. Each of these scenarios is composed of two models, identical by their architecture but different in their internal sedimentary fill. This approach allows the study of the impact of the (a) reservoir bodies’ connectivity and (b) their internal sedimentary heterogeneity on the reservoir’s performances. The capacity estimates using a static calculation based on the available pore volumes reveals a mean capacity of 13 Mt (for a 25 x 25 km x 60 m semi finite aquifer at 1000m deep). The sedimentary heterogeneity (shaly deposits called oxbow lakes) is responsible for a 30% difference of capacity. The flow simulations confirm these results and show that the connectivity of the reservoir bodies creates a 23% capacity variation. Moreover, the heterogeneities tend to reduce the amount of CO2 able to reach the uppermost reservoir which may enhance the storage integrity
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Osselin, Florian. "Thermochemical-based poroelastic modelling of salt crystallization, and a new multiphase flow experiment : how to assess injectivity evolution in the context of CO2 storage in deep aquifers." Phd thesis, Université Paris-Est, 2013. http://pastel.archives-ouvertes.fr/pastel-00977430.
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In a context of international reduction of greenhouse gases emissions, CCS (ce{CO2} Capture and Storage) appears as a particularly interesting midterm solution. Indeed, geological storage capacities may raise to several millions of tons of ce{CO2} injected per year, allowing to reduce substantially the atmospheric emissions of this gas. One of the most interesting targets for the development of this solution are the deep saline aquifers. These aquifers are geological formations containing brine whose salinity is often higher than sea water's, making it unsuitable for human consumption. However, this solution has to cope with numerous technical issues, and in particular, the precipitation of salt initially dissolved in the aquifer brine. Consequences of this precipitation are multiple, but the most important is the modification of the injectivity i.e. the injection capacity. Knowledge of the influence of the precipitation on the injectivity is particularly important for both the storage efficiency and the storage security and durability. The aim of this PhD work is to compare the relative importance of negative (clogging) and positive (fracturing) phenomena following ce{CO2} injection and salt precipitation. Because of the numerous simulations and modelling results in the literature describing the clogging of the porosity, it has been decided to focus on the mechanical effects of the salt crystallization and the possible deformation of the host rock. A macroscopic and microscopic modelling has then been developed, taking into account two possible modes of evaporation induced by the spatial distribution of residual water, in order to predict the behavior of a porous material subjected to the drying by carbon dioxide injection. Results show that crystallization pressure created by the growth of a crystal in a confined medium can reach values susceptible to locally exceed the mechanic resistance of the host rock, highlighting the importance of these phenomena in the global mechanical behavior of the aquifer. At the experimental level, the study of a rock core submitted to the injection of supercritical carbon dioxide has been proceeded on a new reactive percolation prototype in order to obtain the evolution of permeabilities in conditions similar to these of a deep saline aquifer
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Ndjaka, Ange. "THERMOPHYSICAL PROCESSES AND REACTIVE TRANSPORT MECHANISMS INDUCED BY CO2 INJECTION IN DEEP SALINE AQUIFERS." Electronic Thesis or Diss., Pau, 2022. http://www.theses.fr/2022PAUU3003.
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Le stockage du CO2 dans les aquifères salins profonds a été reconnu comme l'une des voies les plus prometteuses pour atténuer les émissions atmosphériques de CO2 et répondre ainsi aux enjeux du changement climatique. Cependant, l’injection du CO2 dans le milieu poreux perturbe considérablement son équilibre thermodynamique. La zone proche du puits d’injection est particulièrement impactée avec une forte réactivité géochimique associée à d’intenses échanges thermiques. Cela a un impact majeur sur l’injectivité du réservoir et l’intégrité du stockage. A ces effets s’ajoute une complexité supplémentaire liée à la présence de deux phases non miscibles : la saumure et le CO2. Ces effets conduisent à des processus Thermo-Hydro-Mécaniques-Chimiques (THMC) fortement couplés, dont les interprétations ne sont pas encore abouties ni formellement implémentées dans les modèles numériques.Ce travail de thèse, associant des mesures expérimentales et des modélisations numériques, porte sur l’étude du couplage entre les gradients thermiques et les processus diffusifs de transport réactif se déroulant dans les aquifères salins, notamment dans la zone proche du puits d’injection. Nous avons étudié les échanges entre une phase froide CO2 anhydre qui s’écoule dans des zones de forte perméabilité, et une phase aqueuse salée chaude piégée dans la porosité de la roche. La stratégie de l'étude commence par une approche simple en milieu libre sans flux de CO2 afin d'étudier la réactivité des solutions salines de différentes compositions chimiques et d’évaluer l'impact d'un gradient thermique sur ce réseau réactionnel.Nous avons développé une cellule expérimentale permettant de superposer 2 à 3 couches de solution de concentration et composition chimique différentes. L’analyse de la lumière diffusée par les fluctuations de non-équilibre de la concentration et de la température permet de remonter aux coefficients de diffusion des sels dans l’eau. Nos résultats sont en bon accord avec les valeurs de la littérature. Pour ce qui est de l’étude du transport réactif diffusif, l’analyse du contraste des images a permis de mettre en évidence le fait que la précipitation de minéral, par mise en contact de deux couches aqueuses de sels réactifs, s’accompagne d’une instabilité convective qui s’estompe dans le temps. La modélisation numérique des résultats expérimentaux avec PHREEQC par une approche de diffusion multi-espèce hétérogène permet de rendre compte des instabilités convectives. Différents gradients de température ont été appliqués au système réactif, tout en conservant une température moyenne de 25 °C. Les observations expérimentales et les interprétations numériques montrent que le gradient de température n'a pas d’influence significative sur le comportement du système.Ensuite, nous avons étudié numériquement le processus de dessiccation (évaporation de l’eau) à l’interface entre une saumure piégée dans la porosité de la roche et du CO2 circulant dans une structure porale drainante, simulant les conditions de l’aquifère du Dogger du bassin parisien. Un modèle couplant l’évaporation de l’eau dans le flux de CO2 et la diffusion multi-espèces hétérogène des sels prévoit l’apparition d’un assemblage minéral au niveau du front d’évaporation, principalement composé d’halite et d’anhydrite. La modélisation de ce phénomène à l’échelle du réservoir nécessite la prise en compte de la vitesse d’évaporation en fonction du taux d’injection du CO2 et de l’évolution de la porosité au niveau de l’interface.Ce travail de thèse a permis de mettre en évidence plusieurs phénomènes physico-chimiques, thermo-physiques et de transport diffusif aux interfaces de phase. Ce qui ouvre de nouvelles perspectives d’amélioration des approches numériques et de modélisation à grande échelle notamment du proche puits d’injection du CO2 et des réservoirs de stockage géologique et soutenir les futurs développements industriels et technologiques pour la transition écologique<br>CO2 storage in deep saline aquifers has been recognised as one of the most promising ways to mitigate atmospheric CO2 emissions and thus respond to the challenges of climate change. However, the injection of CO2 into the porous medium considerabely disturbs its thermodynamic equilibrium. The near-well injection zone is particularly impacted with a strong geochemical reactivity associated with intense heat exchanges. This has a major impact on injectivity of the reservoir and the integrity of the storage. In addition to these effects, there is the added complexity of the presence of two immiscible phases: brine (wetting fluid) and CO2 (non-wetting fluid). These effects lead to highly coupled Thermo-Hydro-Mechanical-Chemical (THMC) processes, whose interpretations have not yet been completed nor formally implemented into the numerical models.This thesis work, combining experimental measurements and numerical modelling, focuses on the study of the coupling between the thermal gradients and the diffusive reactive transport processes taking place in the deep saline aquifers, particularly in the near-well injection zone. We studied the exchanges between a cold anhydrous CO2 phase flowing in high permeability zones, and a hot salty aqueous phase trapped in the porosity of the rock. The strategy of the study starts with a simple approach in a free medium without CO2 flow, in order to study the reactivity of saline solutions of different chemical compositions, and to evaluate the impact of a thermal gradient on this reaction network.We have developed an experimental cell that allow to superimpose 2 to 3 layers of solution of different concentration and chemical composition. The analysis of the light scattered by the non-equilibrium fluctuations of concentration and temperature allows to obtain the diffusion coefficients of salts in water. Our results are in good agreement with literature values. Regarding the study of diffusive reactive transport, the analysis of the contrast of the images allowed us to highlight the fact that the precipitation of minerals, obtained by superimposing two aqueous layers of reactive, is accompanied by a convective instability that fades with time. Numerical modelling of the experimental results with PHREEQC using a heterogeneous multicomponent diffusion approach has allowed us to account for these convective instabilities. Different temperature gradients were applied to the reactive system, while keeping a mean temperature of 25 °C. The experimental observations and numerical interpretations swhow that the temperature gradient has no significant influence on the behaviour of the system. Subsequently, we numerically studied the desiccation process (evaporation of water) at the interface between a brine trapped in the rock porosity and the CO2 flowing in a draining pore structure, simulating the conditions of the Dogger aquifer of the Paris basin. A model coupling the evaporation of water in the CO2 stream and the heterogeneous multicomponent diffusion of salts predicts the appearance of a mineral assemblage at the evaporation front, mainly composed by halite and anhydrite. Modelling this phenomenon at the reservoir scale would requires taking into account the evaporation rate as a function of the CO2 injection rate and the change in porosity at the interface.This thesis work has made it possible to highlight several physicochemical, thermophysical and diffusive transport phenomena at phase interfaces. This opens up new perspectives for improving numerical approaches and large-scale modelling, in particular of near-well injection of CO2 and geological storage reservoirs, and supports future industrial developments and technologies for the ecological transition
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Raza, Arshad. "Reservoir Characterization for CO2 Injectivity and Flooding in Petroleum Reservoirs, offshore Malaysia." Thesis, Curtin University, 2017. http://hdl.handle.net/20.500.11937/57524.
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Reservoir characterization of the Malaysian gas reservoir for CO2 storage is carried out at preliminary and comprehensive level to provide insight into the storage capacity, injectivity, trapping mechanisms (structural, capillary, dissolution, and mineral), and containment. Screening tools are proposed in this study for the selections of reservoir, injection well, and injection zone along with CO2 residual trapping novel method, experimental assessment of compaction effect and numerical modeling scheme to improve the reservoir characterization.
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Syed, Shafiuddin Amer. "Permeability and injectivity enhancement of the near wellbore region fo CO2 enhanmced coalbed methane recovery and CO2 storage." Thesis, Imperial College London, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.534965.
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Beinashor, R. "Effect of halite (NaCl) on sandstone permeability and well injectivity during CO2 storage in saline aquifers." Thesis, University of Salford, 2017. http://usir.salford.ac.uk/44572/.
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Carbon dioxide capture and storage (CCS) is one of the widely discussed options for decreasing CO<sub>2</sub> emissions. This method requires the techniques for capturing purification of anthropogenic CO<sub>2</sub> from fossil-fuel power plants, subsequent compression and transport, and, ultimately, its storage in deep geological formations. Due to the high formation salinity, there is a substantial concern about the near well bore formation dry out as a result salt precipitation in the form of halite (NaCl). The focus was on one of the important physical mechanisms of CO<sub>2</sub> injection into deep saline aquifers. The salt (mainly halite) will eventually fully saturate the brine causing the salt to start precipitating as solids. This solid precipitation could significantly decrease the porosity and permeability of the porous medium. The investigations, in this study, were carried out in three distinct parts: (i) core flooding tests for different sandstone core samples (Bentheimer, Castlegate and Idaho Gray) which were saturated with different brine concentrations to measure the CO<sub>2</sub> flow rate for different injection pressures, (ii) utilising simulated experimental apparatus to estimate the porosity and permeability of the core samples and (iii) Qualitative analysis of porosities using CT scanner. In Part (i), it was found that the CO<sub>2</sub> flow rates vary from 0.4 to 6.0 l/min when using brine solution concentrations of 10, 15, 20 and 26.4% for core flooding tests of the studied sandstone core samples before diluting concentrations with sea water (3.5%), and after diluting by sea water the flow rates vary from 0.6 to 7.0 l/min. The flow rate increase indicates that the injectivity will increase. In part (ii), Helium Gas Porosimeter was used to calculate the porosity of each core sample and the results showed for Bentheimer, Castlegate and Idaho Gray 20.8 %, 25.6 % and 23.4 % respectively. Liquid saturating method was also used to calculate the porosity of each core sample and the results showed 23.6% for Bentheimer, 24.4% for Castlegate and 22.4% for Idaho Gray. Regarding the permeability impairment investigations for both brine permeability and gas permeability, the permeability damage took place due to the salt precipitation (NaCl) phenomenon. For brine permeability, the damage percentage of Bentheimer, Castlegate and Idaho Gray was 40%, 42% and 47%. For gas permeability the reduction due to dry out of saturated samples with 20% brine solution were calculated as 34.5% for Bentheimer, 42% for Castlegate and 50.2% for Idaho Gray. Finally, in part (iii), CT Scan was used to determine each core sample porosity and the results showed 20.7% for Bentheimer, 24.3% for Castlegate and 24.6% for Idaho Gray.
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Osselin, Florian. "Modélisation thermochimique et poroélastique de la cristallisation de sel, et nouveau dispositif expérimental d'écoulement multiphasique : comment prédire l'évolution de l'injectivité pour le stockage du CO2 en aquifère profond ?" Phd thesis, Université Paris-Est, 2013. http://tel.archives-ouvertes.fr/tel-00958697.
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Dans un contexte de réduction internationale des émissions de gaz à effet de serre, les techniques de Captage Transport et Stockage de CO2 (CTSC) apparaissent comme une solution à moyen terme particulièrement efficace. En effet, les capacités de stockage géologique pourraient s'élever jusqu'à plusieurs millions de tonnes de CO2 injectées par an, soit une réduction substantielle des émissions atmosphériques de ce gaz. Une des cibles privilégiées pour la mise en place de cette solution sont les aquifères salins profonds. Ces aquifères sont des formations géologiques contenant une saumure dont la salinité est souvent supérieure à celle de la mer la rendant impropre à la consommation. Cependant, cette technique fait face à de nombreux défis technologiques ; en particulier la précipitation des sels, dissous dans l'eau présente initialement dans l'aquifère cible, suite à son évaporation par le CO2 injecté. Les conséquences de cette précipitation sont multiples, mais la plus importante est une modification de l'injectivité, c'est-à-dire des capacités d'injection. La connaissance de l'influence de la précipitation sur l'injectivité est particulièrement importante tant au niveau de l'efficacité du stockage et de l'injection qu'au niveau de la sécurité et de la durabilité du stockage. Le but de ces travaux de thèse est de comparer l'importance relative des phénomènes négatif (colmatage) et positif (fracturation) consécutifs à l'injection de CO2 et à la précipitation des sels. Au vu des nombreux résultats de simulations et de modélisation dans la littérature décrivant le colmatage de la porosité, il a été décidé de porter l'accent sur les effets mécaniques de la cristallisation des sels et la possible déformation de la roche mère. Une modélisation macroscopique et microscopique, tenant compte de deux modes possibles d'évaporation induits par la distribution spatiale de l'eau résiduelle a donc été développée afin de prédire le comportement mécanique d'un matériau poreux soumis à un assèchement par injection de CO2. Les résultats montrent que la pression de cristallisation consécutive à la croissance d'un cristal en milieu confiné peut atteindre des valeurs susceptibles localement de dépasser la résistance mécanique du matériau, soulignant ainsi l'importance de ces phénomènes dans le comportement mécanique global de l'aquifère. Sur le plan expérimental, les travaux ont porté sur l'utilisation d'un nouveau prototype de percolation réactive afin de reproduire le comportement d'une carotte de roche soumise à l'injection et ainsi obtenir l'évolution des perméabilités dans des conditions similaires à celle d'un aquifère.
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Uzun, Ilkay. "Use Of Pore Scale Simulators To Understand The Effects Of Wettability On Miscible Carbon Dioxide Flooding And Injectivity." Master's thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/2/12606876/index.pdf.
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This study concentrates on the modelling of three phase flow and miscible CO2 flooding in pore networks that captures the natural porous medium of a reservoir. That is to say, the network, that is a Matlab code, consists of different sided triangles which are located randomly through the grids. The throats that connect the pores are also created by the model. Hence, the lengths and the radii of the throats are varying. The network used in this research is assumed to be representative of mixed-wet carbonates in 2-D. Mixed wettability arises in real porous media when oil renders surfaces it comes into prolonged contact with oil-wet while water-filled nooks and crannies remain water-wet. The model developed is quasi-static approach to simulate two phase and three phase flows. By this, capillary pressures, relative permeabilities, saturations, flow paths are determined for primary drainage, secondary imbibition, and CO2 injection cases. To calculate the relative permeability, capillary entry pressures are first determined. Then, hydraulic conductances and flow rates of the network for each grid are obtained. Phase areas and saturations are also determined. It is accepted that the displacement mechanism in drainage and CO2 injection is piston-like whereas in imbibition it is either piston-like or snap-off.
The results of the model are compared with the experimental data from the literature. Although, the pore size distribution and the contact angle of the model are inconsistent with the experimental data, the agreement of the relative permeabilities is promising.
The effect of contact angle in the same network for three phase flow where immiscible CO2 is injected as a third phase at supercritical temperature (32 °<br>C) is investigated. And it is found that, the increase in the intrinsic angles causes decrease in relative permeability values.
As another scenario, two phase model is developed in which miscible CO2 &<br>#8211<br>water is flooded after the primary drainage of the same 2-D network at supercritical temperature (32 °<br>C). This case is compared with the previous case and the effects of miscibility are investigated such that it causes the relative permeability values to increase.
Adsorption is another concern of which its effects are analyzed in a single pore model. The model is compared with the reported experimental data at high temperature and pressures. A reasonable fit is obtained.
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Tian, Liang. "CO2 storage in deep saline aquifers : Models for geological heterogeneity and large domains." Doctoral thesis, Uppsala universitet, Luft-, vatten och landskapslära, 2016. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-279382.
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This work presents model development and model analyses of CO2 storage in deep saline aquifers. The goal has been two-fold, firstly to develop models and address the system behaviour under geological heterogeneity, second to tackle the issues related to problem scale as modelling of the CO2 storage systems can become prohibitively complex when large systems are considered. The work starts from a Monte Carlo analysis of heterogeneous 2D domains with a focus on the sensitivity of two CO2 storage performance measurements, namely, the injectivity index (Iinj) and storage efficiency coefficient (E), on parameters characterizing heterogeneity. It is found that E and Iinj are determined by two different parameter groups which both include correlation length (λ) and standard deviation (σ) of the permeability. Next, the issue of upscaling is addressed by modelling a heterogeneous system with multi-modal heterogeneity and an upscaling scheme of the constitutive relationships is proposed to enable the numerical simulation to be done using a coarser geological mesh built for a larger domain. Finally, in order to better address stochastically heterogeneous systems, a new method for model simulations and uncertainty analysis based on a Gaussian processes emulator is introduced. Instead of conventional point estimates this Bayesian approach can efficiently approximate cumulative distribution functions for the selected outputs which are CO2 breakthrough time and its total mass. After focusing on reservoir behaviour in small domains and modelling the heterogeneity effects in them, the work moves to predictive modelling of large scale CO2 storage systems. To maximize the confidence in the model predictions, a set of different modelling approaches of varying complexity is employed, including a semi-analytical model, a sharp-interface vertical equilibrium (VE) model and a TOUGH2MP / ECO2N model. Based on this approach, the CO2 storage potential of two large scale sites is modelled, namely the South Scania site, Sweden and the Dalders Monocline in the Baltic Sea basin. The methodologies developed and demonstrated in this work enable improved analyses of CO2 geological storage at both small and large scales, including better approaches to address medium heterogeneity. Finally, recommendations for future work are also discussed.
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Sánchez, Jesús Antonio García. "Estudo do fenômeno da auto-intersecção em um anel anisotrópico." Universidade de São Paulo, 2008. http://www.teses.usp.br/teses/disponiveis/18/18134/tde-05022009-100510/.
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Estuda-se numericamente uma placa circular homogênea com furo centrado sob estado plano de deformação. A placa está fixa ao longo do contorno interno e está sob compressão radial uniforme ao longo do contorno externo. O material da placa é elástico-linear e anisotrópico. Apresenta-se a solução analítica do problema, a qual satisfaz as equações governantes de equilíbrio, no contexto da elasticidade linear clássica. Esta solução prediz o comportamento espúrio da auto-intersecção em uma região central da placa. Para evitar este comportamento, utiliza-se uma teoria que propõe encontrar um campo de deslocamento que minimize a energia potencial total do corpo sujeito à restrição de injetividade local para o campo da deformação correspondente. Esta teoria, juntamente com o método das penalidades interiores, permite encontrar uma solução numérica que preserva a injetividade. Esta solução corresponde a um campo de deslocamento radialmente simétrico. Estuda-se a possibilidade de encontrar uma solução rotacionalmente simétrica do problema restrito, em que o campo de deslocamento possua as componentes radial e tangencial, ambas funções somente do raio. Os resultados desta última modelagem mostram que a componente tangencial é nula, indicando que o campo de deslocamento é, de fato, radialmente simétrico. Mostra-se também que a solução do problema do anel converge para a solução do problema de um disco sem furo à medida que o raio do furo tende a zero.<br>This work concerns a numerical study of a homogeneous circular plate with a centered hole that is under a state of plane strain. The plate is fixed at its inner surface and is under uniform radial compression at its outer surface. The plate is linear, elastic, and anisotropic. An analytical solution for this problem, which satisfies the governing equations of equilibrium, is presented in the context of classical linear elasticity. This solution predicts the spurious behavior of self-intersection in a central region of the plate. To avoid this behavior, a constrained minimization theory is used. This theory concerns the search for a displacement field that minimizes the total potential energy of the body, which is a quadratic functional from the classical linear theory, subjected to the constraint of local injectivity for the associated deformation field. This theory together with an interior penalty method and a standard finite element methodology yield a numerical solution, which is radially symmetric, that preserves injectivity. Here, it is investigated the possibility of finding a rotationally symmetric solution to the constrained problem; one for which the associated displacement field has radial and tangential components, which are both functions of the radius only. The numerical results show, however, that the tangential component is zero. It is also shown that, as the radius of the hole tends to zero, the corresponding sequence of solutions tends to the solution of a solid disk.
Book chapters on the topic "Injectivité du CO2"
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A. Sokama-Neuyam, Yen, Muhammad A.M. Yusof, and Shadrack K. Owusu. "CO2 Injectivity in Deep Saline Formations: The Impact of Salt Precipitation and Fines Mobilization." In Carbon Sequestration [Working Title]. IntechOpen, 2022. http://dx.doi.org/10.5772/intechopen.104854.
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Climate change is now considered the greatest threat to global health and security. Greenhouse effect, which results in global warming, is considered the main driver of climate change. Carbon dioxide (CO2) emission has been identified as the largest contributor to global warming. The Paris Agreement, which is the biggest international treaty on Climate Change, has an ambitious goal to reach Net Zero CO2 emission by 2050. Carbon Capture, Utilization and Storage (CCUS) is the most promising approach in the portfolio of options to reduce CO2 emission. A good geological CCUS facility must have a high storage potential and robust containment efficiency. Storage potential depends on the storage capacity and well injectivity. The major target geological facilities for CO2 storage include deep saline reservoirs, depleted oil and gas reservoirs, Enhanced Oil Recovery (EOR) wells, and unmineable coal seams. Deep saline formations have the highest storage potential but challenging well injectivity. Mineral dissolution, salt precipitation, and fines mobilization are the main mechanisms responsible for CO2 injectivity impairment in saline reservoirs. This chapter reviews literature spanning several decades of work on CO2 injectivity impairment mechanisms especially in deep saline formations and their technical and economic impact on CCUS projects.
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FOKKER, P., and L. VANDERMEER. "The Injectivity of Coalbed CO2 Injection Wells." In Greenhouse Gas Control Technologies - 6th International Conference. Elsevier, 2003. http://dx.doi.org/10.1016/b978-008044276-1/50088-x.
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Goodarzi, Somayeh, Antonin Settari, Mark Zoback, and David W. "Thermal Effects on Shear Fracturing and Injectivity During CO2 Storage." In Effective and Sustainable Hydraulic Fracturing. InTech, 2013. http://dx.doi.org/10.5772/56311.
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Mackay, E. J. "Modelling the injectivity, migration and trapping of CO 2 in carbon capture and storage (CCS)." In Geological Storage of Carbon Dioxide (CO2). Elsevier, 2013. http://dx.doi.org/10.1533/9780857097279.1.45.
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SHI, J., and S. DURUCAN. "A numerical simulation study of the Allison Unit CO2-ECBM pilotThe impact of matrix shrinkage and swelling on ECBM production and CO2 injectivity." In Greenhouse Gas Control Technologies 7. Elsevier, 2005. http://dx.doi.org/10.1016/b978-008044704-9/50044-6.
Full textConference papers on the topic "Injectivité du CO2"
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Zakrisson, Johan, Ingrid Edman, and Yildiray Cinar. "Multiwell Injectivity for CO2 Storage." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2008. http://dx.doi.org/10.2118/116355-ms.
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Nagineni, Venu Gopal Rao, Richard Gary Hughes, David D'Souza, and Kenneth Michael Deets. "Evaluation of CO2 Injectivity From Waterflood Values." In SPE Western Regional Meeting. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/132624-ms.
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Jin, M., E. J. Mackay, S. A. Mathias, J. G. Gluyas, W. H. Goldthorpe, and G. E. Pickup. "On the Sensitivity of CO2 Injectivity to Reservoir Facies Architecture." In Fourth EAGE CO2 Geological Storage Workshop. EAGE Publications BV, 2014. http://dx.doi.org/10.3997/2214-4609.20140122.
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McMillan, Burton, Navanit Kumar, and Steven Lawrence Bryant. "Time-Dependent Injectivity During CO2 Storage in Aquifers." In SPE Symposium on Improved Oil Recovery. Society of Petroleum Engineers, 2008. http://dx.doi.org/10.2118/113937-ms.
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André, L. "Well Injectivity during CO2 Storage Operations in Deep Saline Aquifers." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412023.
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Crawshaw, J. P., and E. S. Boek. "Asphaltene Precipitation and Deposition from a Heavy Crude Oil with CO2." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412008.
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Ali*, Syed Anas, Jay R. Black, and Ralf Haese. "Geochemical Stimulation in Siliciclastic Reservoirs to Enhance CO2 Injectivity." In International Conference and Exhibition, Melbourne, Australia 13-16 September 2015. Society of Exploration Geophysicists and American Association of Petroleum Geologists, 2015. http://dx.doi.org/10.1190/ice2015-2210548.
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Alkan, H., and Y. Cinar. "Effects of Capillarity and Solubility in Brine on CO2 Injectivity into an Aquifer." In First EAGE CO2 Geological Storage Workshop. European Association of Geoscientists & Engineers, 2008. http://dx.doi.org/10.3997/2214-4609.20146171.
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Snippe, J. "Long-term Fate of Injected CO2 into a Carbonate Formation, Middle East." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412021.
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Anabaraonye, B., M. J. Blunt, J. P. Crawshaw, A. M. Leal, J. C. Maitland, and C. Peng. "Chemical Interactions between CO2-saturated Brines and Carbonate Minerals at Reservoir Conditions." In First EAGE Workshop on Well Injectivity and Productivity in Carbonates. EAGE Publications BV, 2015. http://dx.doi.org/10.3997/2214-4609.201412022.
Full textReports on the topic "Injectivité du CO2"
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Yoshida, Nozomu, and Philip H. Stauffer. Influence of relative permeability parameters on CO2 injectivity. Office of Scientific and Technical Information (OSTI), 2013. http://dx.doi.org/10.2172/1091808.
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