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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 (January 8, 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 (December 9, 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 (February 1, 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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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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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 (October 1, 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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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 (December 22, 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 (March 2, 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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Fokker, P. A., and L. G. H. van der Meer. "The injectivity of coalbed CO2 injection wells." Energy 29, no. 9-10 (July 2004): 1423–29. http://dx.doi.org/10.1016/j.energy.2004.03.076.
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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 (November 28, 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.
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Azizi, Ehsan, and Yildiray Cinar. "Approximate Analytical Solutions for CO2 Injectivity Into Saline Formations." SPE Reservoir Evaluation & Engineering 16, no. 02 (May 8, 2013): 123–33. http://dx.doi.org/10.2118/165575-pa.
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Summary This paper presents new analytical models to estimate the bottomhole pressure (BHP) of a vertical carbon dioxide (CO2) injection well in a radial, homogeneous, horizontal saline formation. The new models include the effects of multiphase flow, CO2 dissolution in formation brine, and near-well drying out on the BHP. CO2 is injected into the formation at a constant rate. The analytical solutions are presented for three types of formation outer boundary conditions: closed boundary, constant-pressure boundary, and infinite-acting formation. The sensitivity of BHP computations to gas relative permeability, retardation factors, and CO2 compressibility is examined. The predictive capability of the analytical models is tested by use of numerical reservoir simulations. The results show a good agreement between the analytical and numerical computations for all three boundary conditions. Variations in gas compressibility, retardation factors, and gas relative permeability in the drying-out zone are found to have moderate effects on BHP computations. It is demonstrated for several hypothetical but realistic cases that the new models can estimate CO2 injectivity reliably.
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Pooladi-Darvish, Mehran, Samane Moghdam, and Don Xu. "Multiwell injectivity for storage of CO2 in aquifers." Energy Procedia 4 (2011): 4252–59. http://dx.doi.org/10.1016/j.egypro.2011.02.374.
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Azizi, Ehsan, and Yildiray Cinar. "A New Mathematical Model for Predicting CO2 Injectivity." Energy Procedia 37 (2013): 3250–58. http://dx.doi.org/10.1016/j.egypro.2013.06.212.
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Jin, Min, Eric Mackay, Simon Mathias, and Gillian Pickup. "Impact of sub seismic heterogeneity on CO2 injectivity." Energy Procedia 63 (2014): 3078–88. http://dx.doi.org/10.1016/j.egypro.2014.11.331.
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Edem, Donatus Ephraim, Muhammad Kabir Abba, Amir Nourian, Meisam Babaie, and Zainab Naeem. "Experimental Study on the Interplay between Different Brine Types/Concentrations and CO2 Injectivity for Effective CO2 Storage in Deep Saline Aquifers." Sustainability 14, no. 2 (January 16, 2022): 986. http://dx.doi.org/10.3390/su14020986.
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Salt precipitation during CO2 storage in deep saline aquifers can have severe consequences on injectivity during carbon storage. Extensive studies have been carried out on CO2 solubility with individual or mixed salt solutions; however, to the best of the authors’ knowledge, there is no substantial study to consider pressure decay rate as a function of CO2 solubility in brine, and the range of brine concentration for effective CO2 storage. This study presents an experimental core flooding of the Bentheimer sandstone sample under simulated reservoir conditions to examine the effect of four different types of brine at a various ranges of salt concentration (5 to 25 wt.%) on CO2 storage. Results indicate that porosity and permeability reduction, as well as salt precipitation, is higher in divalent brines. It is also found that, at 10 to 20 wt.% brine concentrations in both monovalent and divalent brines, a substantial volume of CO2 is sequestered, which indicates the optimum concentration ranges for storage purposes. Hence, the magnitude of CO2 injectivity impairment depends on both the concentration and type of salt species. The findings from this study are directly relevant to CO2 sequestration in deep saline aquifers as well as screening criteria for carbon storage with enhanced gas and oil recovery processes.
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Qiao, C., L. Li, R. T. Johns, and J. Xu. "Compositional Modeling of Dissolution-Induced Injectivity Alteration During CO2 Flooding in Carbonate Reservoirs." SPE Journal 21, no. 03 (June 15, 2016): 0809–26. http://dx.doi.org/10.2118/170930-pa.
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Summary Geochemical reactions between fluids and carbonate rocks can change porosity and permeability during carbon dioxide (CO2) flooding, which may significantly affect well injectivity, well integrity, and oil recovery. Reactions can cause significant scaling in and around injection and production wells, leading to high operating costs. Dissolution-induced well-integrity issues and seabed subsidence are also reported as a substantial problem at the Ekofisk field. Furthermore, mineral reactions can create fractures and vugs that can cause injection-conformance issues, as observed in experiments and pressure transients in field tests. Although these issues are well-known, there are differing opinions in the literature regarding the overall impacts of geochemical reactions on permeability and injectivity for CO2 flooding. In this research, we develop a new model that fully couples reactive transport and compositional modeling to understand the interplay between multiphase flow, phase behavior, and geochemical reactions under reservoir and injection conditions relevant in the field. Simulations were carried out with a new in-house compositional simulator on the basis of an implicit-pressure/explicit-composition and finite-volume formulation that is coupled with a reactive transport solver. The compositional and geochemical models were validated separately with CMG-GEM (CMG 2012) and CrunchFlow (Steefel 2009). Phase-and-chemical equilibrium constraints are solved simultaneously to account for the interaction between phase splits and chemical speciation. The Søreide and Whitson (1992) modified Peng-Robinson equation of state is used to model component concentrations present in the aqueous and hydrocarbon phases. The mineral-dissolution reactions are modeled with kinetic-rate laws that depend on the rock/brine contact area and the brine geochemistry, including pH and water composition. Injectivity changes caused by rock dissolution and formation scaling are investigated for a five-spot pattern by use of several common field-injection conditions. The results show that the type of injection scheme and water used (fresh water, formation water, and seawater) has a significant impact on porosity and permeability changes for the same total volume of CO2 and water injected. For continuous CO2 injection, very small porosity changes are observed as a result of evaporation of water near the injection well. For water-alternating-gas (WAG) injection, however, the injectivity increases from near zero to 50%, depending on the CO2 slug size, number of cycles, and the total amount of injected water. Simultaneous water-alternating-gas injection (SWAG) shows significantly greater injectivity increases than WAG, primarily because of greater exposure time of the carbonate surface to CO2-saturated brine coupled with continued displacement of calcite-saturated brine. For SWAG, carbonate dissolution occurs primarily near the injection well, extending to larger distances only when the specific surface area is small. Formation water and seawater lead to similar injectivity increases. Carbonated waterflooding (a special case of SWAG) shows even greater porosity increases than SWAG because more water is injected in this case, which continuously sweeps out calcite-saturated brine. The minerals have a larger solubility in brine than in fresh water because of the formation of aqueous complexes, leading to more dissolution instead of precipitation. Overall, this research points to the importance of considering the complex process coupling among multiphase flow, transport, phase behavior, and geochemical reactions in understanding and designing schemes for CO2 flooding as well as enhanced oil recovery at large.
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Zhang, Keni, Yaqin Xu, Lulu Ling, and Yang Wang. "Numerical Investigation for Enhancing CO2 Injectivity in Saline Aquifers." Energy Procedia 37 (2013): 3347–54. http://dx.doi.org/10.1016/j.egypro.2013.06.222.
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Christman, Peter G., and Sheldon B. Gorell. "Comparison of Laboratory- and Field-Observed CO2 Tertiary Injectivity." Journal of Petroleum Technology 42, no. 02 (February 1, 1990): 226–33. http://dx.doi.org/10.2118/17335-pa.
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Dai, Zhenxue, Ye Zhang, Philip Stauffer, Ting Xiao, Mingkan Zhang, William Ampomah, Changbing Yang, et al. "Injectivity Evaluation for Offshore CO2 Sequestration in Marine Sediments." Energy Procedia 114 (July 2017): 2921–32. http://dx.doi.org/10.1016/j.egypro.2017.03.1420.
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Yang, Guodong, Yilian Li, Aleks Atrens, Ying Yu, and Yongsheng Wang. "Numerical Investigation into the Impact of CO2-Water-Rock Interactions on CO2 Injectivity at the Shenhua CCS Demonstration Project, China." Geofluids 2017 (2017): 1–17. http://dx.doi.org/10.1155/2017/4278621.
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A 100,000 t/year demonstration project for carbon dioxide (CO2) capture and storage in the deep saline formations of the Ordos Basin, China, has been successfully completed. Field observations suggested that the injectivity increased nearly tenfold after CO2 injection commenced without substantial pressure build-up. In order to evaluate whether this unique phenomenon could be attributed to geochemical changes, reactive transport modeling was conducted to investigate CO2-water-rock interactions and changes in porosity and permeability induced by CO2 injection. The results indicated that using porosity-permeability relationships that include tortuosity, grain size, and percolation porosity, other than typical Kozeny-Carman porosity-permeability relationship, it is possible to explain the considerable injectivity increase as a consequence of mineral dissolution. These models might be justified in terms of selective dissolution along flow paths and by dissolution or migration of plugging fines. In terms of geochemical changes, dolomite dissolution is the largest source of porosity increase. Formation physical properties such as temperature, pressure, and brine salinity were found to have modest effects on mineral dissolution and precipitation. Results from this study could have practical implications for a successful CO2 injection and enhanced oil/gas/geothermal production in low-permeability formations, potentially providing a new basis for screening of storage sites and reservoirs.
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Sun, Guangyuan, Zhuang Sun, Andrew Fager, and Bernd Crouse. "Pore-scale Analysis of CO2-brine Displacement in Berea Sandstone and Its Implications to CO2 Injectivity." E3S Web of Conferences 367 (2023): 01011. http://dx.doi.org/10.1051/e3sconf/202336701011.
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For storage in deep saline formations, where CO2 is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO2 injectivity is considered to reach the maximum value at the CO2 endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO2-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO2-brine flow in the sample of Berea sandstone. CO2/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO2 storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO2 displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO2 injectivity. The result shows that water-wet condition facilitates the CO2 injection when there is no fracture induced.
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Wang, Yuan, Jie Ren, Shaobin Hu, and Di Feng. "Global Sensitivity Analysis to Assess Salt Precipitation for CO2 Geological Storage in Deep Saline Aquifers." Geofluids 2017 (2017): 1–16. http://dx.doi.org/10.1155/2017/5603923.
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Salt precipitation is generated near the injection well when dry supercritical carbon dioxide (scCO2) is injected into saline aquifers, and it can seriously impair the CO2 injectivity of the well. We used solid saturation (Ss) to map CO2 injectivity. Ss was used as the response variable for the sensitivity analysis, and the input variables included the CO2 injection rate (QCO2), salinity of the aquifer (XNaCl), empirical parameter m, air entry pressure (P0), maximum capillary pressure (Pmax), and liquid residual saturation (Splr and Sclr). Global sensitivity analysis methods, namely, the Morris method and Sobol method, were used. A significant increase in Ss was observed near the injection well, and the results of the two methods were similar: XNaCl had the greatest effect on Ss; the effect of P0 and Pmax on Ss was negligible. On the other hand, with these two methods, QCO2 had various effects on Ss: QCO2 had a large effect on Ss in the Morris method, but it had little effect on Ss in the Sobol method. We also found that a low QCO2 had a profound effect on Ss but that a high QCO2 had almost no effect on the Ss value.
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Hoteit, Hussein, Marwan Fahs, and Mohamad Reza Soltanian. "Assessment of CO2 Injectivity During Sequestration in Depleted Gas Reservoirs." Geosciences 9, no. 5 (May 5, 2019): 199. http://dx.doi.org/10.3390/geosciences9050199.
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Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO 2 transitions from the dense-state to the gas-state, CO 2 density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO 2 expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO 2 expansion is associated with the Joule–Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO 2 injectivity. Understanding the transient multiphase phase flow behavior of CO 2 within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO 2 from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO 2 within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO 2 heating at the wellhead are assessed.
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Sokama-Neuyam, Yen A., Wilberforce N. Aggrey, Patrick Boakye, Kwame Sarkodie, Sampson Oduro-Kwarteng, and Jann R. Ursin. "The effect of temperature on CO2 injectivity in sandstone reservoirs." Scientific African 15 (March 2022): e01066. http://dx.doi.org/10.1016/j.sciaf.2021.e01066.
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Vilarrasa, Victor, Antonio P. Rinaldi, and Jonny Rutqvist. "Long-term thermal effects on injectivity evolution during CO2 storage." International Journal of Greenhouse Gas Control 64 (September 2017): 314–22. http://dx.doi.org/10.1016/j.ijggc.2017.07.019.
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Ibrahim, Ahmed Farid, and Hisham A. Nasr-El-Din. "Effects of Formation-Water Salinity, Formation Pressure, Gas Composition, and Gas-Flow Rate on Carbon Dioxide Sequestration in Coal Formations." SPE Journal 22, no. 05 (March 22, 2017): 1530–41. http://dx.doi.org/10.2118/185949-pa.
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Summary Carbon dioxide (CO2) sequestration in coal seams combines CO2 storage with enhancing methane (CH4) recovery. The efficiency of CO2 sequestration depends on the coal-formation properties and the operating conditions. This study investigated the effects of the sodium chloride (NaCl) salinity of coal-seam water, injection flow rate, injected-gas composition, and CO2 state (formation pressure) on CO2 sequestration in coal formations. Coreflood tests were conducted on nine coal cores to simulate the injection of CO2 into coal formations. The change in the effective water/coal permeability after CO2 injection was measured. A commercial simulator was used to match the pressure drop across the core from the experimental study by adjusting the relative permeability curves. Moreover, permeability dynamic measurements were conducted to estimate the absolute permeability reduction caused by coal swelling. The effective water permeability in the tested coal decreased during CO2 injection because of its adsorption onto the coal surface, coupled with a reduction in the relative water permeability. As salt concentration increased, the change in the pressure drop across the core increased, but this effect decreased as the formation pressure increased. Higher formation pressure and lower nitrogen (N2) concentrations led to further permeability reduction as a result of the higher CO2 adsorption onto the coal surface. Furthermore, as the injection flow rate increased, the contact time of CO2 at the coal surface decreased. Hence, the CO2 adsorption to the coal matrix decreased, and thus the difference in the effective water permeability slightly decreased. CO2 injectivity in fully water-saturated formations increased initially as the gas relative permeability increased, then the injectivity decreased as a result of matrix swelling and absolute permeability reduction. Moreover, the water salinity in coal formations decreased the overall gas relative permeability and increased the water relative permeability. Similar behavior occurred in the presence of N2. It is derived from these observations that the injection of CO2 into highly volatile bituminous coal seams for CO2 sequestration purpose is more efficient as the salt concentration increases, especially at high injection pressures.
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Syahrial, Ego. "Reservoir Simulator For Improved Recovery Of Coalbed Methane (Icbm) Part Ii : Effect Of Coal Matrix Swelling And Shrinkage." Scientific Contributions Oil and Gas 32, no. 3 (March 17, 2022): 193–200. http://dx.doi.org/10.29017/scog.32.3.850.
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Sequestration of CO2 in deep unmined coal seams is currently under development for improved recovery of coalbed methane (ICBM) as well as permanent storage of CO2. Recent studies have shown that CO2 displaces methane by adsorbing more readily onto the coal matrix compared to other greenhouse gases, and could therefore contribute towards reducing global warming. In order to carry out a more accurate assessment of the potential of ICBM and CO2 sequestration, field based numerical simulations are required. Existing simulators for primary CBM (coalbed methane) recovery cannot be applied since the process of CO2 injection in partially desorbed coalbeds is highly complex and not fully understood. The principal challenges encountered in numerical modelling of ICBM/CO2 sequestration processes which need to be solved include: (1) two-phase flow, (2) multiple gas components, (3) impact of coal matrix swelling and shrinkage on permeability, and (4) mixed gas sorption. This part II of this two-part paper series describes the development of a compositional simulator with the impact of matrix shrinkage/swelling on the production performance on primary and echanced recovery of coalbed methane. The numerical results for enhanced recovery indicate that matrix swelling associated with CO2 injection could results in more than an order of magnitude reduction in formation permeability around the injection well, hence prompt decline in well injectivity. The model prediction of the decline in well injectivity is consistent with the reported field observations in San Juan Basin USA. Also, a parametric study is conducted using this simulator to investigate the effects of coal properties on the enhancement of methane production efficiency based on published data.
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Marques, Luiz Carlos do Carmo, and Daniel Monteiro Pimentel. "Pitfalls of CO2 Injection in Enhanced Oil Recovery." Applied Mechanics and Materials 830 (March 2016): 125–33. http://dx.doi.org/10.4028/www.scientific.net/amm.830.125.
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The intent of this paper is to offer a comprehensive understanding of the pitfalls associated with CO2-rich gas injection during enhanced oil recovery (EOR) operations. An emphasis is placed, however, on the interactions between this gas and crude oil asphaltenes, because these later compounds are heavy organic molecules which can destabilize, flocculate and precipitate in CO2-rich environments, thus triggering a major field problem: injectivity loss due to near-wellbore (inflow) formation damage: an Achilles heel for any EOR process.
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Zhang, Zhen, Yuan Wang, and Yang Liu. "State of Indoor Experiments on Supercritical CO2-Brine Displacement System." Advanced Materials Research 864-867 (December 2013): 1208–12. http://dx.doi.org/10.4028/www.scientific.net/amr.864-867.1208.
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As an emerging technique, carbon dioxide capture and storage (CCS) is to mitigate greenhouse gas emissions. Deep saline aquifers are increasingly considered because of their wide distributionlarge thicknesslarge capacity. A proper understanding of displacement character of supercritical CO2-brine system is significant in knowing CO2 Injectivity, migration and trapping, and in assessing the safety and suitability of reservoir site. CO2-brine system is multi-phase flow system, the mobility is related to interfacial tensioncapillary pressurerelative permeability. The experiments took into account the impact factors such as interfacial tensioncapillary pressurerelative permeability, foreign indoor experiments of CO2-brine system are analyzed and summarized, a brief description of indoor experiments of our country and future work are given.
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Giwelli, A., MZ Kashim, MB Clennell, L. Esteban, R. Noble, C. White, S. Vialle, et al. "CO2-brine injectivity tests in high co2 content carbonate field, sarawak basin, offshore east Malaysia." E3S Web of Conferences 89 (2019): 04005. http://dx.doi.org/10.1051/e3sconf/20198904005.
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We conducted relatively long duration core-flooding tests on three representative core samples under reservoir conditions to quantify the potential impact of flow rates on fines production/permeability change. Supercritical CO2 was injected cyclically with incremental increases in flow rate (2─14 ml/min) with live brine until a total of 7 cycles were completed. To avoid unwanted fluid-rock reaction when live brine was injected into the sample, and to mimic the in-situ geochemical conditions of the reservoir, a packed column was installed on the inflow accumulator line to pre-equilibrate the fluid before entering the core sample. The change in the gas porosity and permeability of the tested plug samples due to different mechanisms (dissolution and/or precipitation) that may occur during scCO2/live brine injection was investigated. Nuclear magnetic resonance (NMR) T2 determination, X-ray CT scans and chemical analyses of the produced brine were also conducted. Results of pre- and post-test analyses (poroperm, NMR, X-ray CT) showed no clear evidence of formation damage even after long testing cycles and only minor or no dissolution (after large injected pore volumes (PVs) ~ 200). The critical flow rates (if there is one) were higher than the maximum rates applied. Chemical analyses of the core effluent showed that the rock samples for which a pre-column was installed do not experience carbonate dissolution.
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Chen, Zhongwei, Jishan Liu, Derek Elsworth, Luke D. Connell, and Zhejun Pan. "Impact of CO2 injection and differential deformation on CO2 injectivity under in-situ stress conditions." International Journal of Coal Geology 81, no. 2 (February 2010): 97–108. http://dx.doi.org/10.1016/j.coal.2009.11.009.
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Ren, Guangwei, Bo Ren, Songyan Li, and Chao Zhang. "Unlock the Potentials to Further Improve CO2 Storage and Utilization with Supercritical CO2 Emulsions When Applying CO2-Philic Surfactants." Sustainable Chemistry 2, no. 1 (March 2, 2021): 127–48. http://dx.doi.org/10.3390/suschem2010009.
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Supercritical CO2 (ScCO2) emulsion has attracted lots of attention, which could benefit both climate control via CO2 storage and industry revenue through significantly increased oil recovery simultaneously. Historically, aqueous soluble surfactants have been widely used as stabilizers, though they suffer from slow propagation, relatively high surfactant adsorption and well injectivity issues. In contrast, the CO2-soluble surfactants could improve the emulsion performance remarkably, due to their CO2-philicity. Here, comprehensive comparison studies are carried out from laboratory experiments to field scale simulations between a commercially available aqueous soluble surfactant (CD 1045) and a proprietary nonionic CO2-philic surfactant whose solubility in ScCO2 and partition coefficient between ScCO2/Brine have been determined. Surfactant affinity to employed oil is indicated by a phase behavior test. Static adsorptions on Silurian dolomite outcrop are conducted to gain the insights of its electro-kinetic properties. Coreflooding experiments are carried out with both consolidated 1 ft Berea sandstone and Silurian dolomite to compare the performances as a result of surfactant natures under two-phase conditions, while harsher conditions are examined on fractured carbonate with presence of an oleic phase. Moreover, the superiorities of ScCO2 foam with CO2-philic surfactant due to dual phase partition capacity are illustrated with field scale simulations. ScCO2 and WAG injections behaviors are used as baselines, while the performances of two types of CO2 emulsions are compared with SAG injection, characterized by phase saturations, CO2 storage, oil production, CO2 utilization ratio and pressure distribution. A novel injection strategy, named CO2 continuous injection with dissolved surfactant (CIDS), which is unique for a CO2-philic surfactant, is also studied. It is found that the CO2-soluble surfactant displays much lower oil affinity and adsorption on carbonate than CD 1045. Furthermore, in a laboratory scale, a much higher foam propagation rate is observed with the novel surfactant, which is mainly ascribed to its CO2 affinity, assisted by the high mobility of the CO2 phase. Field scale simulations clearly demonstrate the potentials of CO2 emulsion on CO2 storage and oil recovery over conventional tertiary productions. Relative to traditional aqueous soluble surfactant emulsion, the novel surfactant emulsion contributes to higher injectivity, CO2 storage capability, oil recovery and energy utilization efficiency. The CIDS could further reduce water injection cost and energy consumption. The findings here reveal the potentials of further improving CO2 storage and utilization when applying ScCO2-philic surfactant emulsion, to compromise both environmental and economic concerns.
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JPT staff, _. "Techbits: Coalbed-Methane Recovery and CO2 Sequestration Raise Economic, Injectivity Concerns." Journal of Petroleum Technology 57, no. 03 (March 1, 2005): 26–71. http://dx.doi.org/10.2118/0305-0026-jpt.
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Qu, H. Y., J. S. Liu, Z. J. Pan, and L. Connell. "Impact of thermal processes on CO2 injectivity into a coal seam." IOP Conference Series: Materials Science and Engineering 10 (June 1, 2010): 012090. http://dx.doi.org/10.1088/1757-899x/10/1/012090.
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Kumar, Hemant, Derek Elsworth, Jishan Liu, Denis Pone, and Jonathan P. Mathews. "Optimizing enhanced coalbed methane recovery for unhindered production and CO2 injectivity." International Journal of Greenhouse Gas Control 11 (November 2012): 86–97. http://dx.doi.org/10.1016/j.ijggc.2012.07.028.
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Vulin, Domagoj, Bruno Saftić, and Marija Macenić. "Estimate of dynamic change of fluid saturation during CO2 injection — Case study of a regional aquifer in Croatia." Interpretation 6, no. 1 (February 1, 2018): SB51—SB64. http://dx.doi.org/10.1190/int-2017-0077.1.
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Total carbon dioxide ([Formula: see text]) storage capacities are estimated in numerous studies, but there is a lack of research of possible injection rates at a particular site. We have performed compositional simulation with permeability variation (based on log-normal distribution parameters of the measured data from similar formations in an oil field above the aquifer) to include changes of aqueous and gaseous phase properties (composition, viscosities, density), and heterogeneity of a regional [Formula: see text] storage site. We have performed sensitivity tests on vertical permeability multiplier, different grid block sizes, diffusivity, and capillary pressures to detect the key parameters for injectivity and storage efficiency. In this way, we modeled heterogeneity of a [Formula: see text] storage site and the possible injection rate in this detail for the first time. Based on pressure analysis in simulation cases, we found that it will be hard to avoid fracturing the near-wellbore zone, but fracturing these zones might also increase the injectivity, and this can still be done without damaging the cap rock. Simulation results indicated that maximum pressure will occur in zones above wellbores at the short period after the injection, and almost no change of average pressure in the regional aquifer will be noticeable, which leads to the conclusion that the total (theoretical) storage capacity is not the key issue for [Formula: see text] storage in aquifers and that injectivity for the storage site (expressed as the rate) should be the key parameter for selecting the pilots for [Formula: see text] storage.
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Aghajanloo, Mahnaz, Lifei Yan, Steffen Berg, Denis Voskov, and Rouhi Farajzadeh. "Impact of CO2 hydrates on injectivity during CO2 storage in depleted gas fields: A literature review." Gas Science and Engineering 123 (March 2024): 205250. http://dx.doi.org/10.1016/j.jgsce.2024.205250.
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Silva, Danielle Alves Ribeiro da, Juan Alberto Mateo Hernandez, and Jennys Lourdes Meneses Barillas. "Relative permeability hysteresis analysis in a reservoir with characteristics of the Brazilian pre-salt." Research, Society and Development 12, no. 2 (February 10, 2023): e24712239842. http://dx.doi.org/10.33448/rsd-v12i2.39842.
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The hysteresis of relative permeability and capillary pressure need to be more widespread in academic studies, in order to understand how they can influence reservoirs with light oil and high pressure. These phenomena become extremely important to have a good prediction of oil production, considering that in many cases, the use of hysteresis in calculations can lead to a better prediction of oil recovery, allowing the exploration of certain fields. Thus, this study had as main objective the analysis of two hysteresis models (Killough and Larsen and Skauge) widely used in commercial software, in order to investigate the behavior of a light oil reservoir using a miscible WAG-CO2 process. Thus, to achieve this goal, a semi-synthetic reservoir, with characteristics similar to those found in the Brazilian pre-salt, was considered and was modeled using commercial software from CMG. Hysteresis reduces fluid permeability, which can generate two effects: increased local sweep efficiency of the oil and loss of injectivity. The former effect contributes to increased oil recovery, while injectivity loss can decrease oil sweep, reducing oil recovery. Furthermore, this work found that hysteresis can cause loss of gas and water injectivity, however this did not prevent hysteresis from increasing oil recovery compared to the case without hysteresis.
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Jeong, Gu Sun, Seil Ki, Dae Sung Lee, and Ilsik Jang. "Effect of the Flow Rate on the Relative Permeability Curve in the CO2 and Brine System for CO2 Sequestration." Sustainability 13, no. 3 (February 1, 2021): 1543. http://dx.doi.org/10.3390/su13031543.
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The relative permeabilities of CO2 and brine are important parameters that account for two-phase flow behavior, CO2 saturation distribution, and injectivity. CO2/brine relative permeability curves from the literature show low endpoint CO2 permeability values and high residual brine saturation values. These are the most distinguishing aspects of the CO2/brine relative permeability from oil/water and gas/oil. In this study, this aspect is investigated experimentally by employing a wide range of CO2 injection flow rates. As a result, all the measurements align with previous studies, having low endpoint relative permeability and high residual brine saturation values. They have obvious relationships with the changes in CO2 flow rates. As the CO2 flow rate increases, the endpoint relative permeability increases, the residual brine saturation decreases, and they converge to specific values. These imply that a high CO2 injection flow rate results in high displacement efficiency, but the improvement in efficiency decreases as the flow rate increases. The reasons are identified with the concept of the viscous and capillary forces, and their significance in the CO2 injection into a reservoir is analyzed.
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Smith, Nial, Paul Boone, Adegbenro Oguntimehin, Gijs van Essen, Rong Guo, Michael A. Reynolds, Luke Friesen, Maria-Constanza Cano, and Simon O'Brien. "Quest CCS facility: Halite damage and injectivity remediation in CO2 injection wells." International Journal of Greenhouse Gas Control 119 (September 2022): 103718. http://dx.doi.org/10.1016/j.ijggc.2022.103718.
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Md Yusof, Muhammad Aslam, Muhammad Azfar Mohamed, Nur Asyraf Md Akhir, Mohamad Arif Ibrahim, and Mutia Kharunisa Mardhatillah. "Combined Impact of Salt Precipitation and Fines Migration on CO2 Injectivity Impairment." International Journal of Greenhouse Gas Control 110 (September 2021): 103422. http://dx.doi.org/10.1016/j.ijggc.2021.103422.
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Sokama-Neuyam, Yen Adams, Sindre Langås Forsetløkken, Jhon-eirik Lien, and Jann Rune Ursin. "The Coupled Effect of Fines Mobilization and Salt Precipitation on CO2 Injectivity." Energies 10, no. 8 (August 1, 2017): 1125. http://dx.doi.org/10.3390/en10081125.
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Mathias, Simon A., Jon G. Gluyas, Gerardo J. González Martínez de Miguel, Steven L. Bryant, and David Wilson. "On relative permeability data uncertainty and CO2 injectivity estimation for brine aquifers." International Journal of Greenhouse Gas Control 12 (January 2013): 200–212. http://dx.doi.org/10.1016/j.ijggc.2012.09.017.
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Liu, Hejuan, Qi Li, Yang Gou, Liwei Zhang, Wentao Feng, Jianxing Liao, Zhengwen Zhu, Hongwei Wang, and Lei Zhou. "Numerical modelling of the cooling effect in geothermal reservoirs induced by injection of CO2 and cooled geothermal water." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 15. http://dx.doi.org/10.2516/ogst/2020005.
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The utilization of geothermal energy can reduce CO2 emissions into the atmosphere. The reinjection of cooled return water from a geothermal field by a closed loop system is an important strategy for maintaining the reservoir pressure and prolonging the depletion of the geothermal reservoir by avoiding problems, e.g., water level drawdown, ground subsidence, and thermal pollution. However, the drawdown of water injectivity affected by physical and chemical clogging may occur in sandstone aquifers, and the reservoir temperature may be strongly affected by the reinjection of large amounts of cooled geothermal water, thus resulting in early thermal breakthrough at production wells and a decrease in production efficiency. In addition to the injection of cooled geothermal water, the injection of CO2 can be used to maintain the reservoir pressure and increase the injectivity of the reservoir by enhancing water–rock interactions. However, the thermal breakthrough and cooling effect of the geothermal reservoir may become complex when both CO2 and cooled geothermal water are injected into aquifers. In this paper, a simplified small-scale multilayered geological model is established based on a low-medium geothermal reservoir in Binhai district, Tianjin. The ECO2N module of the TOUGH2MP simulator is used to numerically simulate temperature and pressure responses in the geothermal reservoir while considering different treatment strategies (e.g., injection rates, temperatures, well locations, etc.). The simulation results show that a high injection pressure of CO2 greatly shortens the CO2 and thermal breakthrough at the production well. A much lower CO2 injection pressure is helpful for prolonging hot water production by maintaining the reservoir pressure and eliminating the cooling effect surrounding the production wells. Both pilot-scale and commercial-scale cooled water reinjection rates are considered. When the water production rate is low (2 kg/s), the temperature decrease at the production well is negligible at a distance of 500 m between two wells. However, when both the production and reinjection rates of cooled return water are increased to 100 m3/h, the temperature decrease in the production well exceeds 10 °C after 50 years of operation.
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Pasarai, Usman, Utomo Pratama Iskandar, Sugihardjo Sugihardjo, and Herru Lastiadi S. "A SYSTEMATIC APPROACH TO SOURCE-SINK MATCHING FOR CO2 EOR AND SEQUESTRATION." Scientific Contributions Oil and Gas 36, no. 1 (February 15, 2022): 1–13. http://dx.doi.org/10.29017/scog.36.1.640.
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Carbon dioxide for enhanced oil recovery (CO2 EOR) can magnify oil production substantially while aconsistent amount of the CO2 injected remains sequestrated in the reservoir, which is benefi cial for reducingthe greenhouse gas (GHG) emission. The success of CO2 EOR sequestration depends on the proper sourcessinksintegration. This paper presents a systematic approach to pairing the CO2 captured from industrialactivities with oil reservoirs in South Sumatra basin for pilot project. Inventories of CO2 sources and oilreservoirs were done through survey and data questionnaires. The process of sources-sinks matching waspreceded by scoring and ranking of sources and sinks using criteria specifi cally developed for CO2 EORand sequestration. The top candidate of CO2 sources are matched to several best sinks that correspond toadded value, timing, injectivity, containment, and proximity. Two possible scenarios emerge for the initialpilot where the CO2 will be supplied from the gas gathering station (GGS) while the H3 and F21 oil fi eldsas the sinks. The pilot is intended to facilitate further commercial deployment of CO2 EOR sequestrationin the South Sumatera basin that was confi rmed has abundant EOR and storage sinks as well as industrialCO2 sources.
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Wang, Wendong, Fankun Meng, Yuliang Su, Lei Hou, Xueyu Geng, Yongmao Hao, and Lei Li. "A Simplified Capillary Bundle Model for CO2-Alternating-Water Injection Using an Equivalent Resistance Method." Geofluids 2020 (November 25, 2020): 1–14. http://dx.doi.org/10.1155/2020/8836287.
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CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio.
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Seyyedi, Mojtaba, Ausama Giwelli, Cameron White, Lionel Esteban, Michael Verrall, and Ben Clennell. "Changes in multi-phase flow properties of carbonate porous media during CO2 injection." APPEA Journal 60, no. 2 (2020): 672. http://dx.doi.org/10.1071/aj19061.
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Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.
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Tawiah, Paul, Hongqian Wang, Steven L. Bryant, Mingzhe Dong, Steve Larter, and Jeff Duer. "Effects of temperature and CO2/Brine cycles on CO2 drainage endpoint phase mobility – implications for CO2 injectivity in deep saline aquifers." International Journal of Greenhouse Gas Control 112 (December 2021): 103491. http://dx.doi.org/10.1016/j.ijggc.2021.103491.
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Ding, Yanxu, Yang Zhao, Xin Wen, Yueliang Liu, Ming Feng, and Zhenhua Rui. "Development and Applications of CO2-Responsive Gels in CO2 Flooding and Geological Storage." Gels 9, no. 12 (November 29, 2023): 936. http://dx.doi.org/10.3390/gels9120936.
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Gel systems are widely used as plugging materials in the oil and gas industry. Gas channeling can be mitigated by reducing the heterogeneity of the formation and the mobility ratio of CO2 to crude oil. Cracks and other CO2 leaking pathways can be plugged during the geological storage of CO2 to increase the storage stability. By adding CO2-responsive groups to the classic polymer gel’s molecular chain, CO2 responsive gel is able to seal and recognize CO2 in the formation while maintaining the superior performance of traditional polymer gel. The application of CO2 responsive gels in oil and gas production is still in the stage of laboratory testing on the whole. To actually achieve the commercial application of CO2 responsive gels in the oil and gas industry, it is imperative to thoroughly understand the CO2 responsive mechanisms of the various types of CO2 responsive gels, as well as the advantages and drawbacks of the gels and the direction of future development prospects. This work provides an overview of the research progress and response mechanisms of various types of CO2 responsive groups and CO2 responsive gels. Studies of the CO2 responsive gel development, injectivity, and plugging performance are comprehensively reviewed and summarized. The shortcomings of the existing CO2 responsive gels system are discussed and the paths for future CO2 responsive gel development are suggested.