Publications Database - List of storage publications

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    June, 2005

Vol 2 Chapter 9: Natural Gas Storage Industry Experience and Technology: Potential Application to CO₂ Geological Storage

Kent F. Perry

Abstract: This chapter reviews the portfolio of technologies available within the underground gas storage industries in the United States, Canada, and Europe and evaluates their applicability to geologic CO₂ storage. Gas storage operators have accumulated a significant knowledge base for the safe and effective storage of natural gas. While gas leakage has occurred due to well failures and geologic factors, overall gas storage has been effectively and efficiently performed for over 90 years. There are three types of “gas movement” described in this summary;

1. gas leakage—defined as unwanted gas movement through an intended cap rock
2. gas release—defined as leaking gas having escaped to the atmosphere, and
3. gas migration—unwanted gas movement within a reservoir but contained within the reservoir.

Only 10 of the approximately 600 storage reservoirs operated in the United States, Canada, and Europe have been identified to have experienced leakage, subject to the ability to detect such leakage by monitoring, material balance, and other methods. Most gas leakage incidents in underground natural gas storage operations have occurred due to wellbore integrity problems. Poor cement jobs, casing corrosion, and improperly plugged wells in converted oil and gas fields have all contributed to gas leakage. Remedial action procedures and technologies to address these problems are well established in the oil and gas industry and have been proven to be effective. It is of special note that leakage of natural gas has occurred in at least one field despite application of practically all available technology and integrity determination techniques. Accordingly, the caution directed at the gas storage industry by Dr Donald Katz in the 1960s is applicable to the newly developing carbon dioxide (CO₂) storage industry today. Katz essentially warned that zero leakage is difficult to verify and impossible to guarantee. Assuring rapid detection and repair of any potential leaks is more realistic. A number of technologies developed by the underground gas storage industry in the United States and Europe have been identified as having potential application to geologic CO₂ storage. We have identified 24 technologies or technology areas as having application to geological CO₂ storage. Of those, five technologies/techniques were determined to be most relevant. The five most relevant technologies are:

1. “Watching the Barn Doors” (utilization of all techniques on a continuous basis),
2. gas storage observation wells,
3. pump-testing techniques,
4. cap rock sealing (important approaches have been developed in this area but successful sealing has not been achieved)
5. and surface monitoring.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(305 Kb)      View   Download

    June, 2005

Vol 2 Chapter 10: Leakage of CO₂ Through Abandoned Wells: Role of Corrosion of Cement

George W. Scherer, Michael A. Celia, Jean-Herve Prevost, Stefan Bachu, Robert Bruant, Andrew Duguid, Richard Fuller, Sarah E. Gasda, Mileva Radonjic and Wilasa Vichit-Vadakan

Abstract: The potential leakage of CO₂ from a geological storage site through existing wells represents a major concern. An analysis of well distribution in the Viking Formation in the Alberta basin, a mature sedimentary basin representative of North American basins, shows that a CO₂ plume and/or acidified brine may encounter up to several hundred wells. A review of the literature indicates that cement is not resistant to attack by acid, but little work has been reported for temperatures and pressures comparable to storage conditions. Therefore, an experimental program has been undertaken to determine the rate of corrosion and the changes in properties of oil well cements exposed to carbonated brine. Preliminary results indicate a very high rate of attack, so it is essential to have accurate models of the composition and pH of the brine, and the time that it will remain in contact with cement in abandoned wells. A model has been developed that incorporates a flash calculation of the phase distribution, along with analysis of the fluxes and pressures of the liquid, solid and vapor phases. A sample calculation indicates that wells surrounding the injection site may be in contact with the acidified brine for years.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(901 Kb)      View   Download

    June, 2005

Vol 2 Chapter 11: Long-Term CO₂ Storage: Using Petroleum Industry Experience

Reid B. Grigg

Abstract: This study comprised a survey of Permian Basin reservoirs where CO₂ is being injected for enhanced oil recovery, or where CO₂ injection was seriously considered. The focus was the assessment of successes and problems in these projects. There is significant experience and knowledge in the oil and gas industry to separate, compress, transport, inject, and process the quantities of CO₂ that are envisioned for CO₂ storage. Improvements will occur as incentives, time and fluid volumes increase. In some cases, certain phenomena that had been noted during waterflood were not included in simulating CO₂ processes—an omission that can prove, and has proven in some cases to be detrimental to the success of the project. When the reservoir is well understood, CO₂ has performed as expected. Also, the thermodynamic phase behavior of CO₂ must be honored in predictive models. High-pressure CO₂ performs as expected: it mobilizes oil, dissolves into brine, and promotes dissolution of carbonates. Brine can become supersaturated with dissolved solids; when pressure drops as it advances through the reservoir, precipitants can form. However, the kinetics of dissolution and precipitation under many reservoir conditions requires further study. In the time frame wherein CO₂ has been actively injected into geological formations, seals appear to have maintained their integrity and retained CO₂. Monitoring and verification of CO₂ flow in geological formations is critical to verification of storage, but additional research and monitoring demonstration are needed.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(183 Kb)      View   Download

    June, 2005

Vol 2 Chapter 12: In Situ Characteristics of Acid-gas Injection Operations in the Alberta Basin, Western Canada: Demonstration of CO₂ Geological Storage

Stefan Bachu and Kristine Haug

Abstract: Acid-gas injection in the Alberta basin in western Canada occurs over a wide range of subsurface characteristics, acid gas compositions, and operating conditions. The subsurface characteristics of the injection sites are representative for compacted continental sedimentary basins, like those in the North American mid-continent. No safety or leakage incidents have been reported in the 15 years since the first acid-gas injection operation in the world started in Alberta, and this record indicates that acid-gas injection is a mature technology that can be applied elsewhere in the world. Furthermore, these acid-gas injection operations constitute a commercial-scale analogue for future large-scale CO₂ geological storage operations to reduce CO₂ emissions into the atmosphere from large CO₂ point sources. This review of the subsurface characteristics of the acid-gas injection operations in western Canada provides data and information that can be used in future studies for site selection.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(287 Kb)      View   Download

    June, 2005

Vol 2 Chapter 13: Simulating CO₂ Storage in Deep Saline Aquifers

Ajitabh Kumar, Myeong H. Noh, Gary A. Pope, Kamy Sepehrnoori, Steven L. Bryant and Larry W. Lake

Abstract: We present the results of compositional reservoir simulation of a prototypical CO₂ storage project in a deep saline aquifer. The objective was to better understand and quantify estimates of the most important CO₂ storage mechanisms under realistic physical conditions. Simulations of a few decades of CO₂ injection followed by 103–105 years of natural gradient flow were done. The impact of several parameters was studied, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO₂ in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(1166 Kb)      View   Download

    June, 2005

Vol 2 Chapter 14: CO₂ Storage in Coalbeds: CO₂/N₂ Injection and Outcrop Seepage Modeling

Shaochang Wo and Jenn-Tai Liang

Abstract: Methane (CH₄) production from coalbeds can be enhanced by injection of carbon dioxide (CO₂), nitrogen (N₂), or a mixture of both (flue gas) to accelerate methane production at sustained or increased pressures. Coal has the capacity to adsorb considerably more CO₂ than either methane or nitrogen. However, the actual field performance of enhanced methane recovery processes, wherein CO₂ is concurrently stored, is largely dictated by how effectively injected gases contact and interact with coalbeds over the active project lifetime. By history matching the early nitrogen breakthrough time and nitrogen cuts in BP’s Tiffany Unit, simulation indicated that the injected N2 may only contact a small portion of the total available pay, which was evidenced by the spinner surveys conducted in some of the N₂ injectors. As a possible explanation, the elevated pressure affected by N₂ injection may expand the coal fractures on the preferential permeability trends in the Tiffany Unit. Simulation prediction of CO₂–N₂ mixed gas injections was performed following the history matching in the pilot area. Methane seepage has already been observed from many locations along the north and west Fruitland outcrops in the San Juan Basin. The concern is that injected CO₂ could likely follow the methane seepage paths and leak from the outcrops. Based on the geological setting of the Fruitland coal outcrop, a representative seepage model was used to simulate the effects of CO₂ contact volume (net pay interval) in coal and the injection distance from the outcrop on methane and CO₂ seepage. Under certain conditions, simulation predicted that a large volume of methane and CO₂ breakthrough could occur if the CO₂ injection wells are placed too close to the outcrop.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(1194 Kb)      View   Download

    June, 2005

Vol 2 Chapter 15: CO₂ Conditioning and Transportation

Geir Heggum, Torleif Weydahl, Roald Mo, Mona Mølnvik and Anders Austegaard

Abstract: The aim of the CO₂ Conditioning and Pipeline Transportation project is to advance the development of cost effective and safe methods for CO₂ compression and pipeline transportation. Optimized design for the compression process and pipeline system requires accurate and reliable predictions of fluid properties, particularly density and water solubility. Existing CO₂ pipeline transportation systems (onshore USA and Canada; offshore Norway) are reviewed in terms of operational parameters, particularly drying specifications. Based on calculations of water solubility for a selected case, it is found that the most stringent drying requirements (e.g. 50 ppm proposed for Hammerfest LNG) may be relaxed to ~600 ppm (present USA Kinder Morgan specification). Today there is little experience with subsea pipelines for CO₂ transportation, particularly in deep waters and over long distances. The intension of this study is to build up confidence in the technology and save costs for future projects. Thermodynamic models and tools for calculating properties for CO₂ and CO₂-rich mixtures have been verified against experimental data. For CO₂ density the Lee–Kesler model is in satisfactory agreement with National Institute of Standards and Technology (NIST) data both in gas and liquid phase. For solubility of water in pure CO₂, the Soave–Redlich–Kwong equation of state with adjusted binary coefficient to 0.193 in van der Waals mixing rule can be applied, and gives a good approximation to the data collected from literature. Adding impurities as CH₄, N₂, H₂S and amines to the CO₂ mixture will affect the solubility of water, e.g. adding 5% methane lowers the water solubility in the liquid phase considerably. However, very little experimental data on water solubility in these mixtures is available in the literature. In order to inhibit hydrate formation and prevent excessive corrosion rates for carbon steel, no free water should be allowed in the pipeline. Thus, water removal is usually required upstream of the pipeline inlet. For a typical case, theoretical calculations show that the limit for free water precipitation at supercritical conditions in the pipeline averages ~1300 ppm. This suggests that water content requirements might be relaxed and opportunities for alternative, more cost-effective water removal solutions are provided.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(196 Kb)      View   Download

    June, 2005

Vol 2 Chapter 16: Materials Selection for Capture, Compression, Transport and Injection of CO₂

Marion Seiersten and Kjell Ove Kongshaug

Abstract: The principal alternative for long-distance transportation of CO₂ from source to storage site is in pipelines. To a large extent pipelines can be made in carbon steel as pure, dry CO₂ is essentially non-corrosive. More corrosion-resistant materials or corrosion inhibition must be considered when the CO₂ contains water that condenses out during transportation. This will occur where it is impossible to dry CO₂ to a dew point well below the ambient temperature. Water-saturated CO₂ is corrosive when water precipitates, but experiments show that corrosion rates at high CO₂ pressures in systems containing only water or water/MEG (monoethylene glycol) mixtures are considerably lower than predicted by corrosion models. This applies particularly at low temperatures that are typical for sub-sea pipelines in northern waters. In our previous study, it has been demonstrated that 20 ppm CO₂ corrosion inhibitor is sufficient to lower the corrosion rate below 0.1 mm/y at temperatures up to 30℃ and CO₂ pressures up to 72 bar. The present study focuses on determining the corrosion rate as function of CO₂ pressure up to 80 bar. The results are compared to existing corrosion models that have been developed to cover a pressure range relevant for oil and gas transportation, i.e. pressures up to 20 bar. The objective of the present study was to verify or extend the use of corrosion models at CO₂ pressure above 20 bar. The experiments show that the models overestimate the corrosion rate when they are used above their CO₂ partial pressure input limit. At low temperature the models predict more than 10 times the measured corrosion rate. Furthermore, the results indicate that the corrosion rate has a maximum as function of CO₂ pressure at 40 and 50℃. The maximum is at 30–50 bar depending on temperature. Part of the present study was devoted to determine the solubility of water in CO₂ containing up to 5% CH₄ at high pressure. The results show that CH₄ lowers the water solubility and hence increases the risk of free water in liquid or supercritical CO₂.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(471 Kb)      View   Download

    June, 2005

Vol 2 Chapter 17: Impact of SO_x and NO_x in Flue Gas on CO₂ Separation, Compression and Pipeline Transmission

Bruce Sass, Bruce Monzyk, Stephen Ricci, Abhishek Gupta, Barry Hindin and Neeraj Gupta

Abstract: This study is an assessment of the effects of impurities in CO₂ streams on aboveground processing equipment. It is primarily a literature review that focuses on SO_x and NO_x impurities in flue gas. The three main components of the data analysis include:

1. Impact of impurities on the performance of amine separation systems.
2. Evaluation of the phase behavior of multi-component gas mixtures on multi-stage compressors.
3. Literature review of compressed gases to determine the corrosivity of pipeline materials in contact with CO₂, SO_x, and NO_x species with moisture present.

Flue gas impurities, such as SO_x, NO_x, other trace gases, and volatile metals have the potential of interacting unfavorably with capture, compression, and pipeline transmission of CO₂. Absorption and regeneration characteristics of amines and other solvents used to separate CO₂ are affected adversely by acid gas impurities, as their amine salts form essentially irreversibly. Compression of gas mixtures is subject to condensation of the higher boiling constituents, which may limit the ability to achieve adequate interstage cooling and may damage the compressor and other related processing equipment. Materials used in separation, compression, and transmission are subject to corrosion by acids formed from hydrolysis of SO_x and NO_x species in the presence of water. Finally, metals such as arsenic and mercury are accumulated from the coal and oil, and may hinder downstream processes.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(520 Kb)      View   Download

    June, 2005

Vol 2 Chapter 18: Effect of Impurities on Subsurface CO₂ Storage Processes

Steven Bryant and Larry W. Lake

Abstract: We examine the potential effect of highly reactive impurities (SO_x; NO_x) on two important aspects of largescale geological storage of CO₂: well injectivity and enhanced oil recovery processes. The primary influence on well injectivity is expected to be geochemical alteration of the near-well formation. Our simulations of a “worst-case” scenario indicate that the net change in mineral volume is likely to be small, even though extensive changes in the type of minerals may occur. Thus, the effect on injectivity is likely to be insignificant. The presence of impurities in their likely concentrations of less than 1 mole% may speed up the reactions, but otherwise should have little incremental effect on the injectivity. The effectiveness of enhanced recovery processes using CO₂ depends on factors such as minimum miscibility pressure (MMP), mobility ratio, and gravity number. Correlations for these factors developed over several decades of field experience in CO₂ flooding indicate that impurities at the levels typical of flue gases are unlikely to affect recovery adversely.

Carbon Dioxide Capture for Storage in Deep Geologic Formations – Results from the CO₂ Capture Project Geologic Storage of Carbon Dioxide with Monitoring and Verification - Volume 2
Edited by: Sally M. Benson, Lawrence Berkeley Laboratory, Berkeley, CA, USA

(225)      View   Download

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