Gas Capture To Reduce Toxic Contents In Atmosphere

Published Date: 02 Nov 2017

Shehroz Arfeen Khan

College of Engineering Studies,

University of Petroleum & Energy Studies,

Dehradun(UK)-248001.

Abstract

Current approach to carbon capture and storage (CCS) is passing a power station’s flue gas through an amine based ‘solvent’ which chemically absorbs CARBON DIOXIDE.

Current processes utilise amine solvents, which react with carbon dioxideand hold it in an aqueous solution, allowing other unreactive gases (N2, O2) to pass through.

On heating up to 120 ºC, the CARBON DIOXIDE-rich (loaded) solvent regenerates the carbon dioxideas a gas stream, and the aqueous amine solution (now CARBON DIOXIDE-lean) is re-circulated and cooled for reuse.

Related technology for separating carbon dioxide(and sulfur-containing contaminants, H2S) from other gases has been used for many years for natural gas (e.g. methane, CH4) ‘sweetening’.

However, to have significant impact, post-combustion CCS is required on a much larger scale (>50x) than so far established, and is complicated substantially by the presence of other contaminants in flue gases (O2, SOx, NOx, Hg etc.).

The approach is to introduce new solvent materials for carbon dioxidecapture with superior performance characteristics, low toxicity and volatility and with an improved life-cycle utilising materials from renewable resources.

Keywords: C-Capture, solvent, post-combustion

An Introduction to carbon dioxideSeparation and Capture Technologies

In order to economically produce carbon dioxidefrom power plants, one must first produce high pressure stream of CARBON DIOXIDE. The method of producing this carbon dioxidestream is referred to as separation and capture, which includes operations such as those that take place at the power plant site, including compression. For transport, carbon dioxideis compressed to 100 atm2.

The separation and capturing carbon dioxidefrom the flue gas of power plants had not started with concern about the greenhouse gases. Rather, it gained importance as a possible economic source of CARBON DIOXIDE, especially for use in enhanced oil recovery (EOR) operations where carbon dioxide is injected into oil wells so as to increase the mobility of the oil and, therefore, the productivity of the reservoir. When the price of oil had dropped in the mid-1980s, the recovered Carbon dioxide was too expensive for EOR operations, resulting in closure of the capture stations. Carbon dioxide capture plants were then built to produce Carbon dioxide for commercial applications and markets. A list of the major Carbon dioxide capture plants are given below in table:

Integrated coal gasification combined cycle (IGCC) plants are an example of the hydrogen route. Coal is gasified so as to form synthesis gas containing Carbon monoxide and Hydrogen. The Carbon monoxide reacts with steam to form Carbon dioxide and Hydrogen and the process is known as water-gas shift. Carbon dioxide is then removed, and the H2 is then transferred to gas turbine. This process results in Carbon dioxide removal that is much more efficient than MEA process because capture is from the high pressure synthesis gas as against the atmospheric pressure flue gas. An alike process is available for natural gas, in which the synthesis gas is formed by steam reforming of methane. The hydrogen route opens up opportunities for poly-generation, where besides electricity and CARBON DIOXIDE, additional products are produced. Futhermore, synthesis gas is a high value feed for many chemical processes.

Three basic methods to separate gases

Separation with solvents

Amine scrubbing was established 50 years ago for removal of H2S and Carbon dioxide from gas. Commercially, it is the most established technique available for Carbon dioxide capture but in practical experience streams which are chemically reducing are possible, the opposite of the oxidising environment of a flue gas stream. Mono-ethanolamine (MEA) is the most common type of amine for Carbon dioxide capture. Carbon dioxide recovery rates of 97% and purity in excess of 99% can be attained.

The conditions for Carbon dioxide separation in pre-combustion chamber will be different from those in post-combustion chamber. E.g. In IGCC process, the Carbon dioxide concentration is about 30-40% at a pressure of 25 bars. In this case solvents like Selexol, can be used for pre-combustion capture chamber of Carbon dioxide, and Carbon dioxide can be removed by depressurisation. But the de-pressurisation of the Seloxol also results in a considerable energy penalty.

Membranes

Gas separation membranes permit one component in gas stream through faster than the other components. There are different types of gas separation membrane palladium membranes porous inorganic membranes, inorganic membranes, zeolites, and polymeric membranes.

Membranes cannot attain high degrees of separation, so multiple stages is necessary. This results to increased energy consumption, complexity and costs. Membranes with different characteristics are required to separate high-purity carbon dioxide. Solvent membranes are developed to combine the best features of membranes and solvent scrubbing.

Cryogenics

Carbon dioxide can be separated from other gases by condensation. Cryogenic separation is used for streams that have high carbon dioxide concentrations (typically >80%) but it is not used for dilute carbon dioxide stream.

The dis-advantage of cryogenic separation of carbon dioxide is the large energy requirement to provide refrigeration necessary for the process, particularly for dilute gas streams. Another disadvantage is that water has to be eliminated before the gas stream is cooled, to avoid blockage. Cryogenic separation has the advantage of enabling direct production of liquid carbon dioxide, needed for transport by ship. Cryogenics normally applies to high concentration, high pressure gases, as in pre-combustion capture chamber.

CARBON DIOXIDE RECOVERY

Process

Carbon dioxide recovered from flue gas of steam reformer of ammonia plant is transported to carbon dioxide compressor for urea synthesis. Recovered carbon dioxide increases urea production. The first plant for flue gas carbon dioxide recovery using this technology started in Malaysia in October 1999 for Urea production. The efficiency is high in terms of steam consumption, low solvent loss and very low solvent degradation.

Flue Gas Carbon dioxide Recovery Technology

Advantages

- High carbon dioxide Loading

- Negligible Corrosion

- Negligible Solvent Degradation

Process

- Solvent Consumption & Low Utility

- Maintenance & Easy operation

Economy

- Minimize Operation Costs

- Large Scale Unit due to Scale of Economy

Characteristics of the flue gas from coal fired boiler

The flue gas contains more Nitrogen oxides, Sulphur oxides, halogens and dust compared with that from natural gas-fired boiler.

Flue Gas Desulfurization (Acid Gas Removal) Systems

Gas velocity

Gas distribution system

Scrubber design

pH

Liquid-to-gas ratio

Turndown ability

The term flue gas desulfurization has been related to wet scrubbers that remove SO2 emissions from large electric utility boilers. But due to requirement of controlling acid emissions from industrial boilers and incinerators and the evolution of different types of acid control systems, acid gas or acid rain control are used interchangeably to define variety of control system designs.

In wet FGD scrubbing system scrubbing liquid is composed of an alkali reagent to increase absorption of Sulphur dioxide and various other acid gases. Sodium-based solution gives better SO2 solubility and much less scaling problems than limestone. But sodium reagents are very expensive.

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Re-generable process gives products from the sludge that is to be sold to partially offset the cost of operation of the FGD. Most FGD systems have two stages:-

First for sulphur dioxide removal and the other for fly ash removal. Methods are present to remove both fly ash and Sulphur dioxide in one scrubbing vessel. But these systems underwent many maintenance problems. In wet scrubbing systems flue gas passes first through a fly ash removal section and then into the Sulphur dioxide absorber.

Liquid-to-gas ratio - The ratio of scrubber liquid slurry to gas flow (L/G ratio). Minimum L/G ratio is achieved during Sulphur dioxide absorption, based on the solubility of Sulphur dioxide in the liquid. High L/G ratios require more piping and structural design considerations, resulting in higher costs.

pH - Depending on the particular type of FGD system, pH must be kept within a certain range to ensure high solubility of Sulphur dioxide and to prevent scale build up.

Gas velocity - Scrubbers operate at maximum practicable gas velocities minimizing vessel size. Maximum velocities are controlled by gas-liquid distribution characteristics and by the maximum allowable liquid entrainment that the mist eliminator can handle.

Gas distribution - Maintaining a uniform flow is a major problem occuring in FGD scrubbers. If the flow is not uniform, the scrubber will not operate at design efficiencies. However, uniform flow has been difficult to achieve.

Scrubber designs - Common type of scrubbers are venturi-rod, mobile-bed scrubbers, plate towers, packed towers, and spray towers.

Sulfur content - The sulfur content, together with the allowable emission standards, determines the required SO2 removal efficiency, the FGD system complexity and cost, and also affects sulfite oxidation.

Ash content - May affect FGD system chemistry and increase erosion. In some cases, it may be desirable to remove fly ash upstream from the FGD system.

Chlorine content - May require high-alloy metals or linings to combat corrosion for some process equipment and could affect process chemistry or require prescrubbing.

Regenerable FGD Processes

Regenerable FGD process remove Sulphur dioxide from flue gas and generate a commercial product. Regenerable products are sulphur, sulphuric acid, limestone scrubbing, gypsum. Regenerable processes do not produce sludge, so no sludge disposal problem. Most regenerable processes also attain:

Use of scrubbing liquids do not cause scaling and plugging problems. The major drawback of is that the system using them are more complicated in design and expensive to install and in operation.

2 regenerable processes curently working in the MgO2. This is used in both sulfuric acid and petroleum companies but has only been installed on a limited count of industrial and utility boilers. The magnesium oxide method has been used at a number of utility boilers, but the Stations are the one and only utility boilers presently operating this process. Because of the limited use of regenerable processes in the process industry, it is not used often.

Nonregenerable FGD Processes

Nonregenerable FGD method produce a sludge or waste product. The sludge must be disposed of properly in a river/lake. The three most common non-regenerable process used on utility boilers are lime, limestone, and double-alkali. Although the double-alkali process regenerates the scrubbing reagent, it is classified as garbage as it does not produce a saleable product and makes solids that must be disposed of in a land. The fourth non-regenerable process mentioned here, sodium-based waste systems (NaOH and Na2CO3), are utilized mostly on development utilities.

Reducing CARBON DIOXIDE: Capturing Carbon Dioxide Directly from Air

The procedure might firstly be used to supply carbon dioxide for such industrial applications as fuel refining from algae or further oil recovery. But the technique could later be used to used as the capture of carbon dioxide from power plant flue gases as part of efforts to reduce ratios and proportions of the atmospheric warming nature. Even if we remove carbon dioxide from all the flue gas, we wouldd still only get a part of the carbon dioxide emitted each year.

Flue gases have about 15% carbon dioxide, while carbon dioxide found in the air at less than 400 parts per million(ppm). That’s a factor of 375, notes the difference in capture efficiency could be partially made up by eliminating the need to make carbon dioxideremoved from flue gas to remote places. The technical and commercial challenges are similar to those of flue gas capture, prototype at count, demonstration of long-span adsorbent stability and demonstration of process efficient and stability, Increased funding for air capture work is required, because wide area of the funding invested in carbon capture over the past 10 years has been used at flue gas capture.

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CONCLUSION:

The studies predict the stability carbonation product to be NaHCO3 at 60oC and 70oC for carbonation(carbon ratio) conditions of 8% CARBON DIOXIDE, 16% water and balance

Helium gas. Different stable phases at 80oC are estimated. Na2CO3•3NaHCO3 is the notified solid product using studies and detailed planning and NaHCO3. X-ray diffraction analysis of the carbonation bi products from a fixed-bed reactor test making use of

SBC-3 at a ambient carbonation temperature of 70oC results in the products were

approximately 85% salt (Na2CO3•3NaHCO3) and balance sodium Carbonate (Na2CO3) [Green, et. al., 2002]

Single-cycle electro balance check using SBC samples produced good Rate of producing again. Reaction rate and final achievable capacity decreased with increasing with flue gas in atmosphere.