Earlier Supercritical CO2 Technologies
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Earlier Supercritical CO2 Technologies 


(Below) How a turbine exhaust recuperator was used in a helium cooled very high temperature prismatic TRISO-powered fast-neutron nuclear reactor.



Oil Hybrid CO2 Carbon Captured Power Plant
(Pairs of 250 megaWatt(e) electricity generators, plus very high temperature steam or solar salt heat is possible from the two heat recovery steam generators. Custom design them for the temperatures you need.)
Unlikely you'll want to use the steam turbine electricity generator in a Renewable Biosynfuel Factory environment. Just delete it and use the heat for carbon capture's reboiler and process heat.

(Below) This is an 'Oxyfuel' oil burning 100% carbon-captured gas turbine powered Hybrid CO2 Energy Park
Oxyfuel carbon-capture produces 100% carbon-capture, making it as clean as a wind turbine.

 Discussion pages>  Foreword     Oil Industry 2.0     Cheaper Than Coal?     The Technology
Equipment pages  1 Original Plant Site  2 Plant Renovation Project  3 Energy Park and Industrial Power Plants  4 Hydrogen, Steam Generators  5 Biomass Preparation Equipment  6 Plasma Torch Gasifier  7 GTL Refinery  8 Fuels Description




Natural Gas or Oil Allam Cycle Power Plant
Midwest Regional Carbon Sequestration Partnership: 





Coal or Lignite Allam Cycle Power Plant
Midwest Regional Carbon Sequestration Partnership: 



Another, perhaps more promising and more efficient, oxy-fuel approach would be the Allam cycle.          Watch: 


CO2 Cleanup



Michigan is the #17 oil producing state.


Some of Southwest Michigan's unneeded coal power plants (think B.C. Cobb) are sitting directly above some of the world's best CO2 sequestration strata.
All the plant needs to do to dispose of CO2 is to drill straight down several thousand feet to make a CO2 disposal well. 

Known global CO2 disposal locations.


Crude Oil as a Gas Turbine  fuel
(Extracted from Siemens Industrial Turbomachinery Ltd. pdf document "Gas Turbine Fuel and Fuel Quality Requirements for use in Industrial Gas Turbine Combustion".)

Viscosity is one of the key parameters used when evaluating liquid fuels for use in industrial gas turbines and generallyshould be <10cst (most regular diesel fuels <7.5cst @ 40degC).

There are cases where neither diesel nor gaseous fuels are available and the only "fuel" is crude oil. This creates challenges that have to be handled through fuel pre-treatment and fuel injection system functionality {11}. Firstly, heating the fuel reduces the viscosity, but noting the limitations:

§ First is 100°C, at which water boils off (all liquid fuels contain a small amount of water) causing cavitations in fuel pumps

§ Increasing fuel oil supply pressure allows the heating to be extended beyond 100°C, but is limited by the temperature limits within the fuel delivery system

§ Further heating can result in fuel cracking and coking in the fuel system and burners depending on the constituents within the crude oil

Crude oils need to be treated in order to meet industrial gas turbine limits on metallic and other contaminants in the fuel. Crude oil often contains high amounts of alkali metals (Na, K) and heavy metals (V, Ni, etc) which if introduced into the combustion system can result in accelerated deposit formation and high temperature corrosion in gas turbine hot gas path components. Major corrosive constituents include Vanadium pentoxide (V2O5), sodium sulphate (Na2SO4) and aggressive low melting forms in the Na2SO4 – V2O5 and Na2O-V2O5 systems. Determination of the ash sticking temperature is usually a good feature to use, and should be >900degC if sticking to the blade is to be avoided. Water and sediment can be removed, or reduced, by filtration and centrifuge separation. This is the same for any liquid fuel, and prevents the formation of corrosive elements and bacterial growth, a pre-cursor to fuel degradation. Removal of the water also reduces the levels of water-soluble contaminants such as the alkali metals sodium and potassium. Vanadium and other heavy metals are oil-soluble though, and can only be treated through chemical dosing so that combustion creates high melting temperature compounds.

Crude oils can also contain more volatile components with a low flash point therefore the need to include explosion proof equipment is often required.


Footnotes & Links

This facility is clearly defined by the U.S. Nuclear Regulatory Commission, local and national building and electrical codes, and supplemented by constraints from the relevant equipment manufacturers.

This website is still a draft. The candidate document's footnote numbers go with a private database. Copy the document's title and submit it to Google. The document may still be posted on the Internet.


(Relocated From Front Page)


Many countries and regions have only tiny or depleted oil patches (i.e., like Michigan), lack advanced energy infrastructure, and need something like Hybrid CO2.
1. CO2 emissions can be reduced to near-windmill levels by adding amine carbon capture to the turbine's exhaust (somewhat like adding a catalytic converter to a car).
2. Substantial reductions in the cost of plant energy since you are making your own Enhanced Oil Recovery (EOR) CO2 and burning its unrefined crude oil.
(If you add postcombustion carbon capture, plan on the amine equipment taking up as much as 4 acres.)

CO2 is used two ways in the above Hybrid CO2 Energy Park.
1, In a carbon-neutral fuel-product loop where plants extract CO2 from the air, the carbon (the ‘C’ in CO2) is extracted from the plants and used as one of the essential ingredients (carbon carries the hydrogen in hydrocarbon combustion fuels) to make synthetic gasoline, diesel, jet fuel, etc. When the vehicle exhausts the burnt fuel's CO2 back into the air, this creates an energy cycle that does not add to, or reduce, Climate Change.
2. Using CO2 for ‘Enhanced Oil Recovery’ to power the Hybrid CO2 Energy Park itself. In most parts of the world there are trace oil patches that cannot be profitably pumped because the oil is attached to rocks and won’t flow easily by itself. The Permian basin oil patch in Texas is an example. For instance, Michigan is the U.S.' 17th largest oil producing state. Many of its wells are 10 barrels-a-week 'strippers'.
It so happens that liquefied CO2 acts as a solvent when mixed with crude oil. Oil companies pay good money to buy tank cars full of liquefied CO2 and inject it, along with water, into the ground in a circle around underground patches of oil. This loosens the oil from its surrounding rocks and the water pushes the now loose oil toward oil wells located in the circle's center. These oil wells pump the oil and CO2 mixture to the surface and into tanks. The CO2, being a gas under pressure, bubbles to the top of the oil where it is recaptured, then recompressed to re-liquefy it, and then is injected into the ground again. Not all of the oil is recovered and, after several trips up and down, the CO2, unable to free up all the oil every time, is lost (sequestered) underground forever.
Typically, one barrel of CO2 will get you about 5 barrels of crude oil before the CO2 is completely absorbed by the ground forever.





Latest GTs pose special challenges for NOx, CO catalyst system design

Posted on by Team CCJ   ( CCJOnSite Web )
The state-of-the-art gas turbines (GTs), such as the H-class and J-class machines, are designed to maximize fuel-to-electricity efficiency, achieving and even exceeding 60% in combined-cycle mode. Already, there are an impressive number of these machines in the field; one supplier listed 80+ H-class GTs operating, in commissioning, being installed, or on order.

This achievement is accomplished through increased firing temperatures, upgraded combustion staging, and advanced metallurgy. The tradeoff to higher temperature, of course, is increased thermal-NOx formation. Dan Ott, president, Environex Inc told the editors that the burden of turbine-exit NOx emissions ends up on the SCR system ( ), at least to achieve the same stack emissions as specified for F-class sites.

Additionally, he said, these machines are being promoted for even faster starts, more frequent cycling, and operation at loads down to 20% compared to the 50%-to-baseload range historically required of earlier designs. Lower-load operation coupled with higher exhaust NOx levels present a demanding set of design challenges for the post-combustion NOx and CO catalyst systems.

Currently, gas-fired turbines often are required to achieve 2- to 2.5-ppmvdc stack NOx, 2- to 5-ppm ammonia slip, and CO limits of 1 to 6 ppm. These limits became a de facto standard, at least in the US, after they were demonstrated based on F-class and aeroderivative engines with typical turbine-exit NOx between 9 and 20 ppmvdc. 

The new H-class machines exhibit 25 to 30 ppmvdc NOx emissions (Fig 1) with some excursions above 35 ppmvdc. This is by no means a trivial increase, Ott stressed. The SCR system designs are going from 75% to 85% NOx removal for F-class units to designs of 92% to 94% removal efficiency for the new advanced turbines. Higher conversion rates mean more catalyst, more frequent catalyst replacement, far more elaborate ammonia injection grids, and more frequent tuning.

Equally important to the SCR design is the impact from the ammonia-slip limit. A Frame 7F turbine with dry-low-NOx technology and a turbine-exit NOx level of 9 ppmvdc can rather easily meet a 2-ppm NOx/2-ppm ammonia-slip limit with 78% NOx removal and allowance for 22% excess ammonia (2-ppm stack/9-ppm inlet = 22%). When the turbine-exit NOx increases to 30 ppm, a 2-ppm NOx/2-ppm ammonia-slip limit requires 93% NOx removal with only 7% excess ammonia.

The success of the SCR design is critically dependent on the amount of excess ammonia that can be injected. Systems should be designed for greater excess ammonia at higher NOx removal requirements, Ott said, but the regulations currently do not allow this.

Fig 2 compares designs with different NOx-removal and excess-ammonia allowances, taking into account the complexity and operability of the designs. Note that most of the newest, higher-efficiency designs are in the “highest risk” zone where the risk of failure on commissioning is high and maintenance (catalyst replacement, catalyst cleaning, and ammonia tuning) is frequent and costly.

All turbines, including the newest designs, are now required operate at low and variable loads to respond to dynamic grid demands. This is in due in part to the growing impact of renewable power. Output down to 20% load is not uncommon.

Figs 3 and 4 show real-time operating data for NOx and CO emissions versus load for an advanced-class turbine. Most low-NOx/low-CO combustor technology is designed to function within guaranteed limits for NOx and CO above 50% load. Below that, NOx and CO increase rapidly because of suboptimal fuel/air mixing. These spikes in emissions at low load require the SCR and CO catalyst systems to achieve emissions reductions as high as 98%, far exceeding the capability of most designs. 

Ott’s conclusions: “We have reached the limit of current SCR and CO catalyst technology. We must increase awareness of these issues and look for broader solutions, including modified hardware and regulatory relief, to allow these new turbines to perform as required in an increasingly dynamic and unpredictable energy market.”



Footnotes & Links

 A small single unit coal power plant located over a prime Carbon Capture disposal strata in Michigan.



This website is still a draft. The candidate document's footnote numbers go with a private database. Copy the document's title and submit it to Google. The document may still be posted on the Internet.