Le Roux Combustion

I am convinced that an understanding of how heat is transferred from the fire to the water in a packaged fire tube boiler will enable operating staff to take a new look at how they manage the fire on the stoker grate.

For all practical purposes a steam boiler is nothing more than a furnace connected to or integrated with a heat exchanger. Apart from combustion, heat transfer in a boiler is one of the more critical processes for the production of steam. This is why a steam boiler is designed to absorb and transfer the maximum amount of heat released from the combustion process to the water drum where the heat of combustion is converted into steam energy.

Please keep in mind that I am still dealing with boilers firing pea coal on a moving chain grate stoker. With a horizontal steam boiler the stoker typically divides the furnace space into two halves down its length – a top half where combustion takes place, and a lower or bottom half which is actually wasted space, except that it collects some spilt ash that does not drop straight into the ash port. The significance of this arrangement is that heat transferred from the fire through the furnace wall only passes through approximately 50% of the available furnace heat transfer surface. In this respect gas and oil fired boilers offer significantly more heat transfer surface per similarly sized furnace.

Without proper heat transfer from the fire to the water:

• the steaming capacity of the boiler is greatly impaired; and
• useful heat is carried along in the flue gas and discharged to waste.

With this in mind, let us look at the factors influencing heat transfer in a boiler.

1. Heat transfer within a steam boiler takes place in three different ways – radiation, convection and conduction.
2. The rate of heat transfer is driven by the temperature difference between the fire/flame/flue gas and the water. Since the water temperature is normally fixed by the steam pressure, the only way of maximizing the temperature difference is to maximize the temperature of the fire/flame. In Boiler Bits 15 I have indicated how the flame temperature of fuel can be determined, but what it boils down to is that increasing excess air above the optimum level decreases the temperature of the flame. Thus the rate of heat transfer is strongly affected by how well excess air is being controlled. It is a known fact that increasing excess air also increases the flue gas exit temperature.
3. The modern fire tube boiler with its water cooled walls absorbs approximately 60% of the heat from the burning of the fuel by means of radiation heat. That heat travels in the form of light waves from the glowing hot fire directly to the furnace walls.
4. The magnitude of radiation heat transfer is driven by a factor (Tf⁴ – Tw⁴), where Tf is the absolute temperature of the fire and Tw the absolute temperature of the furnace wall.
5. All wall surfaces (furnace flue, boiler tubes and tube plates) in contact with the water absorb heat by convection from the hot combustion gases. This mode of heat transfer is primarily driven by gas velocity and turbulence. The higher the turbulence, the higher the rate of heat transfer from hot combustion gas to colder metal surfaces.
6. Heat absorbed by the wall surfaces pass through the steel by conduction. The rate of conduction is driven by the temperature difference between the heated steel surface and the colder wet surface of the water side.
7. Lastly then heat is transferred from the water side steel surfaces to the boiler water by means of convection, although the process is more complex because of the simultaneous presence of steam bubbles and water at the heat exchange interface. This is a phenomenon known as “nucleate boiling”.

What then is the significance of all of this for steam plant operations?

1. Since the largest portion of heat transfer in a boiler is by means of radiation, it calls for huge emphasis to be placed on the management and performance of the furnace.
2. A long fire provides for a greater furnace surface area to be exposed to the temperature of the fire, increasing the amount of radiation heat transferred and reducing the amount of heat carried along in the flue gas. This definitely enhances boiler steaming capacity and leaves less energy in the flue gas which may be lost through the stack. Short fires are generally bad news, both in terms of steaming capacity and stack heat loss.
3. Regardless of heat transfer processes and magnitudes, the efficiency of a steam boiler still reflects in the temperature of the exit flue gas. The closer the temperature gets to the saturated steam temperature, the better the heat transfer and efficiency of the boiler are. It is therefore essential that the exit flue gas temperature be continuously monitored as a means of verifying the integrity of heat transfer within the steam boiler.
4. Keep surfaces exposed to radiation clean, specifically the walls of the furnace flue.
5. Convective heat transfer takes place through a stagnant boundary layer of flue gas and air which exists between the furnace or tube wall and the flue gas. This layer acts to insulate the metal from the flue gases. The slower the velocity of the gases, the thicker is the boundary layer and the slower the rate of heat transfer becomes. Unfortunately limited means are available to increase velocity and/or turbulence in coal fired boiler tubes to scrub the boundary layer down to minimum thickness. Best is to make sure the boiler is correctly matched with the steam demand and that minimum fan speeds at minimum load are carefully selected.
6. Over firing of the boiler may cause departure from nucleate boiling (DNB). When this occurs, steam forms so rapidly on tube walls that heat transfer to the water is impeded, causing steaming capacity to drop and flue gas temperature to rise.
7. Scale deposits on heat exchange surfaces increases the resistance of heat flow through the steel walls and adds to stack heat loss. By way of example, a 2 mm layer of fire scale can cause 5% energy loss, a 1 mm layer of water side scale between 2% and 6%, depending on the density of the scale. It is therefore imperative that every effort be made to ensure that:

• Water treatment programmes are in place, and are monitored and managed.
• Coal procurement is a well managed process, including regular assessment of coal for fouling tendencies.
• Fire side tube fouling is monitored continuously. A modern boiler control system should be able to raise alarm when tube fouling reaches an unacceptable level.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about efficiency of combustion or combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

I am often questioned by operating staff as to the approximate temperature of the fire in the furnace of their boiler. It is clear that people perceive the fire to be quite hot and are often inquisitive to know exactly how hot. Especially if the guillotine door suffers heat damage, steel components warp and melt and even coal ash fuses into sizeable clinkers.

Good news is that there is a scientific way of calculating or estimating the flame temperature in absence of a suitable temperature measuring device. So we will be taking the scientific route to determine the flame temperature with coal as our source of fuel.

When coal (containing mostly carbon) is burned in the presence of oxygen we know that 1 atom of carbon combines with 2 atoms of oxygen to form 1 molecule of carbon dioxide, and that heat to the tune of 32,8 MJ is liberated per kg of carbon so combusted. With bituminous coal the energy released varies, but let us assume that with a 26 MJ/kg coal the carbon content is close to 80%.

Our first challenge is to determine the adiabatic temperature of combustion, i.e. a combustion process without heat loss or gain and under stoichiometric conditions. So this is very much a test tube exercise. Air and fuel enters the test system at ambient temperature, the heat of combustion is released in the combustion reaction and the products of combustion (POC) are elevated to the flame temperature. In its most elementary state the equation looks something like this:

CV = POC*Cp*(Tf-Ta), where CV is the calorific value of the fuel, POC is the mass of the products of combustion (flue gas and ash), Cp is the specific heat of the POC, Tf is the flame temperature, and Ta is the ambient temperature of the fuel and air entering the combustion space. It is then possible to calculate the approximate flame temperature (Tf) from this formula.

By way of example: One kg of a certain coal of 26 MJ/kg CV requires 8,8 kg of air for stoichiometric combustion. The POC thus consists of 9,8 kg of combustion gas and ash (combustion calculations are not shown here). For the sake of simplicity we are going to assume the Cp of the POC to be 1,35 kJ/kg⁰C and ambient temperature to be 25 ⁰C. This results in an adiabatic flame temperature of 2054 ⁰C, assuming no heat loss from the combustion process. If we now add 60% excess air to the process the POC becomes 15,0 kg with corresponding adiabatic flame temperature of 1345 ⁰C. Pretty hot in any man’s language and able to soften and melt steel, but substantially lower than with stoichiometric combustion.

In terms of efficiency and heat transfer we can clearly see from the example above that excess air even has an influence on the furnace (flame) temperature, and if 60% of heat is transferred by means of radiation, it is so much more important to keep the flame temperature as high as possible and to exercise proper control over the air-fuel ratio of combustion.

I once witnessed the practical influence of excess air on furnace temperature. This was at a sawmill where wood chips were burned in a Dutch Oven (external furnace) to produce steam. The furnace temperature is monitored continuously and kept below 1100 ⁰C to prevent damage to the refractory. The engineer believed he could improve the efficiency of combustion by increasing the furnace temperature and reducing the stack temperature. This was easily achieved by regulating the air supply to the furnace through two dampers in the front wall. By partially closing the dampers the furnace temperature would increase rapidly, as one would expect in light of the explanation above: less excess air results in a higher flame temperature. Unfortunately this phenomenon cannot be so easily observed with a compact packaged boiler.

By the way, have you ever considered firing your boiler with coal and pure oxygen? POC is reduced to 2,85 kg and calculated adiabatic flame temperature increases to a staggering 6780 ⁰C!

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about efficiency of combustion or combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

We recently had the privilege to supply and install a rather advanced boiler control system for a brewery in a neighbouring country. The system contained all the bells and whistles normally associated with a system of this nature and we set aside sufficient time for training of both the operating and management staff, which took place in three separate sessions.

At each session there was only one question during Q&A time – where can we see the daily coal consumption? I almost got the impression that we misinterpreted the client’s requirements for a control system – in reality they only needed an accurate coal counter, which we could have provided at a fraction of the cost of a full blown control system.

It wasn’t long before we discovered the somewhat overly interest in a coal counter – the performance of the steam plant was measured by one indicator only, namely coal usage per unit of liquor produced. Although it seems like a logical measure of performance, it would only make sense if the coal characteristics remained consistent for all time. Which brings me to the way one should look at coal and indicators based on its usage.

For many a person involved with steam production coal is a generic term for a black solid fossil fuel delivered in gravel size chunks, of which the quality is determined by the grade: A-grade being the best and D-grade being rather poor. To worsen matters coal procurement is often made the responsibility of the Buyer – a person who in all probability has never seen a boiler in operation. And his only perceived contribution is buying A-grade coal (which it often is not when delivered!) at the lowest cost.

Fact is that coal is merely the carrier of the energy required to produce steam. The energy content (referred to as calorific value or CV) is released during combustion of the coal. Now the peculiar thing about coal is that there are numerous characteristics determining its ability the convert it’s CV into usable energy. Even coal of various origins with similar CV may render different efficiencies when fired in the same boiler. (I will address significant coal characteristics in a future publication, so please accept as fact what is written here for now).

By implication then a kg of A-grade coal from various sources will not necessarily render the same quantity of steam. It thus becomes clear that the value added by coal is not so much in the CV of coal burned, as in the efficiency with which the CV can be converted into useful energy. In this respect the cost per unit of useful energy released by coal plays a much bigger role in the productivity equation than anything else. This then also implies that D-grade coal (at lower price per ton) can be more productive than A-grade coal (at higher cost per ton).

Time for an example.

1. Coal X has a CV of 27800 kJ/kg and the user pays R1450 per ton delivered on site. Based on an analysis of the coal and its combustion properties it is calculated that one kg of this coal would yield 21,98 MJ of useful energy, and 8,74 kg of steam. The cost paid per GJ of useful energy thus amounts to R65,97.
2. Coal Y has a CV of 25600 kJ/kg and the user pays R1320 per ton. Using the same methodology as with Coal X one kg of this coal would yield 20,28 MJ of useful energy. However, the cost paid per GJ of useful energy amounts to R65,09 in this instance, although the steam to coal ratio is only 8,07.

Since the quantity of energy required to produce a unit of steam (and product) remains the same in all instances, the cost per ton of steam is proportional to the cost per GJ of useful fuel energy. If we assume that one GJ of energy produces 0,4 tons of steam under specific operating conditions, then the fuel cost contribution to the cost per ton of steam produced is as follows:

• Coal X:    R166,05
• Coal Y:    R162,73

Those whose performance is measured against the steam-coal ratio indicator will probably jump at the opportunity to get hold of Coal X, ignoring the fact that it is not really such a great contributor to productivity as Coal Y would be. Furthermore, if a batch of Coal Y lands on site, the steam-coal ratio will drop significantly, despite the fact that productivity has improved.

My personal opinion of the matter is that the only sensible and accurate indicator for the efficiency of steam generation is the contribution of the cost of coal to the cost per unit of steam. And this number is really easy to calculate – the only data required is total steam (or even feed water) used, total coal consumed and the cost of coal delivered on site. 

The great advantage of this indicator is that it can be put to good use to optimize combustion conditions. By changing coal suppliers (coal characteristics), excess air, steam pressure control set point, etc. one may be able to find a combination of coal and combustion settings which yield the lowest cost per unit of steam.

Please note that the above example does not consider the fouling tendencies of coal, which may contribute towards more regular cleaning of boiler tubes.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about efficiency of combustion or combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

Often it is only in retrospect that one appreciates the value of certain things which happened in your life, or the course your career has taken. One of the great opportunities life offered me was to have worked under the supervision of a very talented engineer. Not only was he an intelligent person, but he would always approach a problem from first principles. “If nothing changes, everything stays the same” was one of his favourite slogans, and often assisted us in a remarkable way to get to the root of many problems. But what I remember best was his way of critical thinking about situations. And to some extent I think this has greatly influenced my way of looking at and evaluating challenging situations crossing my path.

In my dealings with users of steam boilers critical thinking has often left me amazed at how easily persons, even management, believe the most ridiculous claims made by vendors and persons responsible for boiler plant in respect of boiler performance and efficiency. Claims like 98% boiler efficiency, 10 tons of steam per ton of coal and 30% fuel savings after a control system upgrade are not uncommon. However, if in doubt I go back to first principles to test the claims made and to formulate my own opinion on the matter.

In many circles the efficiency of a coal boiler is expressed in terms of a “steam to coal ratio” number, or SCR in short. A consistent SCR of 7,5 tons of steam per ton of coal is more or less the dividing line between good and exceptional. This of course depends in the first place on the quality of the coal used. With A and B grade coals the 7,5 SCR target is well within reach, in conjunction with a premium combustion control system. With lower coal grades the SCR will obviously drop, which renders the SCR not a true indicator of efficiency, as it uses coal usage, rather than energy input, as the basis of its calculation.

But let us go back to basics and investigate a specific scenario by assuming we burn 27,7 MJ/kg coal in a boiler operating at 10 bar gauge pressure with feed water at 80 ᵒC. Flue gas temperature is at 230 ᵒC and oxygen at 7% (50% excess air). A pretty efficient operating profile, rendering a SCR of 8,5 as per my combustion calculator. This is as close to best one can get with a premium combustion control system without flue gas heat recovery.

In view of this bench mark let us investigate a few other scenarios:

1. In a “from and at” situation (popular with boiler manufacturers when specifying boiler capacity) the feed water temperature is assumed to be at saturated steam pressure, which normally is atmospheric or 100 ᵒC. Under these conditions, and assuming similar coal as with our bench mark model, SCR can reach 9,6. If the boiler operates at a hypothetical 100% efficiency (no energy losses) the SCR reaches a theoretical maximum of 12,27.
2. Using D-grade coal (25,0 MJ/kg) with the same boiler as above, but with feed water temperature at 30 ᵒC and flue gas temperature at 250 ᵒC and 16% oxygen, the system only renders a SCR of 4,2. I believe this is as bad as it can get.
3. Thus the worst of operating conditions can double the coal usage compared to best operating practices.
4. But to be fair in one’s comparison of combustion control systems we must assume that we use the same coal and feed water in both instances, and that only certain relevant combustion parameters change because of a control system upgrade or replacement.
5. This takes us back to our bench mark system which is based on a premium control system, with a SCR = 8,5 as calculated previously. If we assume this boiler was previously fitted with a manual control system and that operators could only manage 14% flue gas oxygen level (200% excess air), it would have rendered a SCR of 7,3. The overall improvement gained from worst to best would be 17,3%, based on the lower efficiency.

What do we learn from all of these numbers?

• If it appears too good to be true, it probably is.
• Do not believe everyone who claims a SCR in excess of 8,5 unless stack heat is being recovered. Anything approaching 9,0 must be treated with a good measure of suspicion, as this will only be possible if all heat losses, except stack losses, are ignored.
• Do not believe everyone who claims to have saved in excess of 20% fuel as result of an upgraded control system. It just does not happen so easily in that way, unless other interventions took place at the time of the upgrade, such as boiler cleaning, upgrading of condensate return, burning of higher CV coal, etc. The norm for fuel savings due to upgrading a basic control system is between 6% and 15%.
• Mostly excessively high efficiency is a matter of incorrect measuring of coal used and/or steam produced. With coal the accurate estimation of usage is normally a problem due to challenges with estimating opening and closing coal stock. With steam consumption it is customary to measure feed water flow as a substitute for steam flow. Any blow down or other water wastage after the flow meter counts for steam production. High levels of feed water wastage can significantly boost the SCR. And this wastage often goes unnoticed.
• Normally short term determination of SCR is not accurate; one has to calculate this number on at least a daily basis, covering at least a 24 hour period.
• It is the duty of the user of the boiler to be objective regarding efficiency claims made by vendors and even by operating staff. And there is only one way of doing this – revert to the first principles governing the matter. If the claims made do not tie up with first principles the red lights must start flickering. 

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

I recently entered a boiler house while accompanying a colleague who had to go see a user regarding a steam outsourcing opportunity. So it was none of my business really, but I could not help noticing that the boiler, which was rated at 10 bar steam pressure, was being operated at only 5 bar pressure. My first thought was that the boiler was undersized and could not cope with the required steam demand.

My question to the engineer regarding the steam pressure elicited a most unexpected reply: he was instructed to operate the boiler at low pressure to save fuel. My natural response was: do you succeed in delivering sufficient steam to the production plant? to which he replied in the negative. At best they battled to meet the steam demand, with an oversized boiler pumping out steam at 5 bar pressure.

The steam supply situation is understandable. At 5 bar pressure a specific mass of steam occupies 78% more volume than at 10 bar. This means that to move a certain steam flow at 5 bar requires it to travel at 78% higher velocity through the pipe system than at 10 bar. In this instance the pipe diameters were just too small to cater for the required steam flow and velocity at 5 bar, hence the production processes were starved of steam. In this particular instance the user was prepared to risk production throughput and product quality for the sake of a perceived fuel saving.

Were they saving energy? Nobody could say how much or explain why they should. The laws of physics tell us they should. Reducing the steam pressure also means reducing the saturated steam (and boiler water) temperature and hence the temperature of the flue gas exiting the boiler through the stack. In the case under discussion the temperature reduction is approximately 25 ᵒC (you may check the steam tables to verify this number). Using this temperature difference in my combustion calculator I arrive at a fuel saving of 1,9%.

With lower boiler water temperature one may expect surface radiation and convective heat losses to be less too; however with a well insulated boiler the effect is negligible.

Another risk to be considered is one of condensation and precipitation of certain elements in the flue gas at sufficiently low temperature. When sulphur-bearing fuel is burned, sulphur is converted into sulphur dioxide (SO2) and sulphur trioxide (SO3). If the flue gas is cooled sufficiently, condensation will occur and droplets will appear on surfaces at temperatures below the dew point. The liquid phase will contain highly corrosive sulphuric acid. Depending upon the concentrations of SO3 and water vapour, the dew point temperature can vary from approximately 90 ᵒC to 140 ᵒC. Condensation of these acids results in metal wastage and flue gas duct corrosion. In order to avoid or reduce the cold end corrosion the gas temperature leaving the heat transfer surface in the boiler must be kept at or above 150 ᵒC.

In conclusion: is operating a boiler at reduced pressure really worth the risk of restricted steam flow and cold end corrosion? I would say yes, provided production/operations is not starved of steam and flue gas temperature can be maintained above 150 ᵒC all the way to the point of discharge, even if it means applying thermal insulation to the boiler stack.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about efficiency of combustion or combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

In our previous publications we have touched on the contribution of combustibles (smoke) to the total boiler energy loss, and although this loss is not really significant, the impact of smoke on the environment can be rather negative and downright emotional from the public’s perspective.

To add to the problem of smoke the construction of your standard horizontal fire tube boiler does not really promote the suppression of smoke, neither does high volatile coal. After all, the smoke originates from the volatile gases which are liberated from the coal when exposed to heat from the ignition arch.

So what is smoke? Smoke originates from hydrocarbons in volatile gases (C-H combinations, e.g. methane an ethylene). At high enough temperature the hydrocarbons decompose into their elements of hydrogen and carbon. The hydrogen molecules combine immediately with oxygen from the combustion air, leaving the carbon molecules in suspension, waiting for more favourable combustion conditions before combining with oxygen. In absence of sufficient oxygen or high enough temperature the carbon particles will not burn and escape through the stack as visible dark smoke. So it seems that smoke is the product of incomplete combustion, caused by either too low excess air supply, or by “cold combustion”.

Insufficient combustion air is easy to understand. It means that not all carbon atoms find a pair of oxygen atoms to combine with. This can be caused by either too low a percentage of excess air, or by insufficient mixing of combustion air and volatiles (i.e. lack of turbulence in the furnace).

The presence of cold combustion can sometimes be observed when looking through the rear peep hole. Looking up towards the roof of the furnace a blanket of dark smoke may be observed, drifting on top of the fire. A boundary layer of “cold” gases can develop along the furnace walls and roof, which are submerged by relatively cold water.  In this boundary layer the temperature is too low to sustain ignition and the carbon laden combustible gas passes through the flue gas passages and the stack to the atmosphere as dark smoke.

Smoke normally shows when the boiler load is low. Combustion air flow may be low at that time, with laminar rather than turbulent flow in the furnace. Poor air and gas mixing takes place, as well as ample time for the combustibles to cool down along the roof of the furnace. Once the boiler operates at higher load the smoke may disappear to some extent, or completely.

Is there a way to suppress smoke development in a boiler? Yes, it can be done, but it may require a number of interventions.

1. Under severe smoking conditions it will not be possible to eradicate all smoke, but improvement of the situation can be achieved.
2. High volatile coal is the main contributor to smoke. Use lower volatile coals if possible; 28% volatiles is about the upper limit if no other suppression methods are applied.
3. Segregation of coal creates a condition where a section of coal on the stoker grate, containing a higher percentage of fines, is starved of oxygen and becomes a source of smoke formation. Devices such as swinging chutes and scatter plates can successfully eliminate this phenomenon and contribute to an even distribution of coal across the width of the grate.
4. Ensure adequate excess air is always supplied to the fire without invoking excessive stack losses. A well designed control system should be able to cater for this requirement.
5. Improve turbulence in the furnace. With some boilers operating at a low furnace pressure (below -20 Pa) can help to some extent, but increased tramp air may inhibit combustion efficiency.
6. The best way in combating smoke is to improve turbulence by introduction of over fire (secondary) air to the furnace. This over fire air enhances mixing of combustible gases with combustion air (oxygen) which is required for complete combustion thereof. Care must however be exercised that this over fire air does not contribute to cold combustion or unacceptable stack loss. (Contact us for more information regarding this intervention).
7. Prevent cold combustion. The over fire air can be used to direct volatiles away from the cold zones towards the fire where temperatures are sufficiently high to cause them to ignite. 
8. Ensure slow and consistent release of volatiles from the coal. This can be achieved with modulating capacity control, a wide steam pressure control band width, elimination of coal segregation and sourcing coal with low duff content.
9. Ensure the boiler furnace is of adequate size (volume) to successfully burn high volatile fuels, such as husk or wood. Too small a furnace may inhibit proper mixing of air and volatiles.
10. Do not feed the furnace too hard. The rate of release of volatiles may exceed the capacity of the furnace to meet requirements for air and volatiles mixing, and even the capacity of fans to supply sufficient supply air for complete combustion of the fuel. 

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

Efficiency in boiler operations is serious business, and rightfully so. A coal steam boiler typically consumes 20 times the value of its capital investment in the cost of fuel during it economic lifespan. So if one spends any amount of effort acquiring the right boiler for the job, one should by comparison spend 20 times as much effort in ensuring that every bit of fuel produces its maximum contribution to the process of steam generation. Considering too that the basic design of the packaged fire tube boiler has not undergone any significant change since the times when coal was generally plentiful, cheap and of excellent quality, making it so much harder for steam users to improve efficiency with odds stacked against their reasonable efforts.

It is therefore clear that achieving high boiler plant efficiency is no stroke of luck or something that falls into one’s lap. It takes hard work, understanding, dedication and excellent management to continuously operate a steam boiler at peak efficiency. And all for one objective: to produce steam at the lowest cost per unit. But also understanding that assets must be preserved and the carbon footprint minimized in pursuit of peak efficiency.

So let us jump straight into some of the definitions pertaining to “efficiency”, and there is a multitude of different interpretations of it; one can easily get totally confused. But in essence efficiency expresses as a percentage the ratio of useful energy output from a system to the total energy input into the system. In a boiler environment the energy input comes from the fuel, the energy output is found in the energy added to the produced steam.

In a perfect system without any energy loss the efficiency will be 100%. Unfortunately we live in a broken world and energy loss in any thermal system is a reality. The real challenge is minimizing the energy loss from the system on a continuous basis, remembering always that energy once lost from the system cannot be recovered!

Our first challenge is to clarify the value of energy input per unit of fuel. Some schools prefer gross calorific value (GCV, also called higher heating value), others net calorific value (NCV, also called lower heating value). The difference between the two is the latent heat of water vapour formed during combustion. Thus NCV = GCV – Latent Heat. Using GCV renders a lower efficiency percentage than when NCV is used. So next time you encounter boiler efficiency statistics and comparisons, clarify beforehand if it is based on GCV or NCV. It can make a significant difference, particularly with oil and gas fired boilers where the hydrogen content of the fuel is relatively high. With coal fired boilers it is customary to use GCV in efficiency calculations; with oil and gas fired boilers it is NCV. 

To complicate matters further efficiency can be calculated in two different ways; according to the direct method or to the indirect method.

The direct method is based on energy added to the steam as a percentage of the fuel energy input. The equation below renders the system (or overall or thermal) efficiency (not the boiler efficiency!), where

1. The added energy is calculated as (Steam energy – energy of feed water), and 
   1. Steam energy = Steam Flow * Saturated steam enthalpy (the latter available from steam tables).
   1. Feed water energy = Steam Flow * Feed water enthalpy, (also available from steam tables, or calculated = 4.2 * feed water temperature deg. C).
2. The fuel input energy = Fuel feed * Calorific value.
3. System efficiency % = Added energy * 100 / Fuel energy.
4. Now note that the direct method incorporates all energy losses in the system, including those encountered in the steam and condensate reticulation systems and in the production facility where the steam is used. This is the most practical and popular way of calculating system efficiency, as all of the required parameters to do the calculation are normally readily available. The equation is often simplified by substituting feed water flow for steam flow, which means blow down quantity is ignored. The bigger challenge is probably to accurately measure steam and fuel usages. 
5. Physical steam and condensate losses are reflected in the make-up water quantity, while energy losses are reflected in the temperature of the feed water to the boiler (without any steam being added).

The indirect method starts off with 100% of fuel energy input and then deducts individual calculated or estimated energy losses encountered within the combustion process, such as stack loss, carbon loss, blow down loss, shell loss, etc. The indirect method calculates energy loss across the boiler only and normally fails to address energy loss downstream of the boiler, i.e. along steam and condensate lines and in steam application processes. These can however be approximated if the make-up water percentage and temperature is known, since make-up water replenishes downstream steam and condensate losses. I use this approach in my combustion calculator; not absolutely accurate, but sufficiently useful for purposes of evaluating boiler performance under various operating conditions, or with coal of differing characteristics.

In the Boiler Bits 9 issue we have identified the following significant energy losses from the boiler:

1. Stack loss, consisting of dry heat loss, combustibles loss and wet loss.
2. Shell loss, consisting of radiation and convection losses.
3. Bottom ash loss
4. Blow down loss

By definition then:

1. Combustion Efficiency % = (100% – Stack loss %)
2. Boiler Efficiency % = (Combustion Efficiency % – Shell Loss % – Bottom ash loss % – Blow down Loss %*)
3. System Efficiency % = (Boiler Efficiency % – Reticulation and Process Loss %).

*   Some schools classify blow down loss as part of system loss.

One may encounter foreign terminology to express steam plant efficiency, or certain aspects thereof. In all instances make sure a clear understanding is gained of how this particular efficiency is defined and calculated; particularly if efficiencies are compared between boilers as part of a new boiler acquisition investigation. It is absolutely essential that one compares apples with apples in all instances.

In the next issue of Boiler Bits I will be discussing what levels of efficiency are considered top notch and achievable on a sustainable basis, specifically with chain grate fire tube boilers.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

BOILER BITS 9: THE NATURE AND MAGNITUDE OF ENERGY LOSSES IN STEAM BOILERS

If the optimization of boiler efficiency is one of the Engineer’s KPA’s, one would expect him/her to know in more than superficial detail where and how energy losses occur in the boiler, their magnitudes, their relative priorities and remedies. For those who would like to know more our next issues of Boiler Bits will touch on the many ways in which efficiency can be calculated and expressed, as well as realistic targets for efficiency.

In this issue however I would like to discuss the origins and magnitudes of energy loss in a typical pea coal fire tube boiler. The diagram above shows the most common heat losses from the boiler. Most significant are the stack losses (4 of them in total), not only in number, but also in magnitude. And then we also have shell loss (convection and radiation), bottom ash loss and blow down loss. Steam distribution and plant losses are not indicated. Tramp air loss (not shown here) may be significant; its effect is similar to that of added excess air and contributes to increased dry heat loss.

Most heat losses can be calculated fairly accurately, however I am not going to indulge in any formulas and calculations to demonstrate how one arrives at the losses mentioned here and elsewhere. The purpose of Boiler Bits is after all to gain an understanding of specific boiler and combustion related principles, rather than presenting an academic dissertation on topics covered.

So, let us take a closer look at the heat losses of boiler operations :

Dry Heat Loss: this is the energy carried in the flue gas and is dependent on its quantity (mass) and temperature. It is thus obvious that increased excess air, as well as tramp air ingress (higher flue gas mass flow), increases this heat loss. Fouled boiler tubes, and operating the boiler at high capacity, also achieve increased dry heat loss on account of higher flue gas temperature. Installing flue gas heat recovery equipment reduces heat loss due to the lower temperature of flue gas discharged to atmosphere. Typical dry heat loss varies between 10% and 20% of gross fuel energy. 

Wet Loss is the name given to latent energy lost in water vapour entrained by the flue gas. Water vapour is formed in two different ways:

• through the evaporation of surface and inherent moisture contained in the fuel, and
• the chemical combination of hydrogen contained in the fuel with oxygen to form water vapour.

Both processes absorb heat from the combustion process, which it can only release again during condensation, i.e. at flue gas temperature below some 60 ⁰C. This heat is in most instances unrecoverable and for all practical purposes energy lost. Burning coal containing 3,5% hydrogen (from ultimate analysis) and 3% inherent moisture (from proximate analysis) the following losses are experienced:

• evaporation of inherent moisture = 0,3%, and
• hydrogen combustion = 3,3%.

Total wet loss = 3,6%. It is interesting to note that inherent (and surface) moisture plays a relatively insignificant role in total wet heat loss.

Combustibles Loss is normally associated with dark smoke from the stack and typically manifests where the fuel is starved of combustion air (oxygen). The dark colour of the smoke comes from carbon molecules in the flue gas, but the flue gas may also contain other products of incomplete combustion, such as carbon monoxide (CO). The magnitude of combustibles energy loss is mostly relatively low; typically less than 1%. Its greater significance is with air pollution and agitating the public and authorities at large because of the visibility of the smoke.

Carbon Loss is associated with fine particles of unburned fuel carried along with the flue gas and being expelled through the stack, or caught up in a grit collector or flue gas filtration system. Because this heat loss depends on so many different factors it is not easy to calculate. As a general rule carbon loss is assumed to be between 0,2% and 0,5%. 

Shell Loss represents a more or less constant heat loss from the boiler due to the temperature difference between the boiler shell and the operating environment. So whether the boiler is operating at 10% load or at 100% load the rate of energy loss through the shell remains the same. It is generally accepted that shell loss = ±2% of the fuel energy at full load. A boiler operating at half load will thus waste some 4% of the fuel energy through its shell.

Bottom Ash Loss depends on the coal characteristics and can be calculated from the carbon in the ash, as well as the temperature of the ash. However, the temperature of the ash makes a minor contribution to the ash loss; it is the carbon in the ash that really counts. If we assume 22% carbon in the ash at a temperature of 350 ⁰C the corresponding bottom ash energy loss will typically be as follows:

• carbon energy loss = 3,6%
• ash temperature loss = 0,18%
• Total bottom ash loss = 4,78%.

Blow down Loss: this loss depends on the volume of condensate returned, as well as the TDS of the make-up water. Note that the percentage blow down volume is significantly more than the percentage blow down heat loss. This is so because we are blowing down water and not steam. Blow down volume normally varies between 2% and 5% of steam produced, whilst blow down energy loss is typically less than 1% of total fuel energy.

What is of particular interest regarding the above heat losses are the following:

• Excess air has the greatest influence on heat losses, namely dry heat loss, combustibles loss and to some extent bottom ash loss. Close control of the combustion process (excess air) is key to high boiler efficiency.
• Coal is an integral part of the combustion system; it dictates the excess air requirements and determines the condition of the bottom ash. It also causes fire side scale which impacts on the rate of heat transfer to the boiler water.
• Returning as much condensate as possible reduces plant, as well as blow down energy losses.
• Operating the boiler at higher capacity is advantageous in terms of shell loss percentage, but increases the flue gas temperature and hence dry heat loss.
• Oversized boilers tend to be inefficient.
• On average adding 10% excess air to the fire reduces overall thermal efficiency by 1%. Increasing flue gas oxygen from 8% to 9% adds 22% to the excess air percentage and will increase the fuel bill by 2,6%. Compelling numbers to make us look at combustion optimization from a new perspective!

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

In Boiler Bits 7 we discussed the merits of oxygen trim control and arrived at a most exciting conclusion, namely that a mathematical relationship exists between excess air and the oxygen content of the flue gas. If we know the one, the other can be calculated. So once we have established the best excess air level for most efficient combustion of the fuel, our control system simply has to adjust the air-fuel ratio to produce the corresponding oxygen level. And with a modern zirconium oxygen sensor ultimate combustion control has come within reach! 

Well, in theory at least. There is however one major drawback, as well as a few minor ones.

Ideally the oxygen sensor must be located right there where combustion is taking place – in the furnace. But with furnace temperatures soaring to some 1200 ⁰C and higher the zirconium oxygen sensor has little chance of surviving the combustion environment. So logically we move it to a location downstream of the furnace, normally somewhere between the boiler’s flue gas exit and the ID (induced draught) fan where flue gas temperatures are less hostile. And yes, I am specifically referring to pea coal boilers where an ID fan is employed as a rule to move the flue gas towards the stack, whilst maintaining a negative furnace pressure to keep the combustion gases safely within the confines of the furnace and flue gas passages.

Unfortunately negative pressure spells trouble. It causes ingress of ambient air (also referred to as tramp air) wherever the integrity of the furnace or flue gas passages under negative pressure are compromised. Leaking seals, ash port doors and joints, warped covers, etc., all create openings through which tramp air seeps into the flue gas passages. And to crown it all a short fire on the stoker leaves ample room towards its rear end for combustion air to pass through the grate unaffected by the fire. As much as 50% of combustion air can pass through the rear end of the grate if under grate dampers are not set correctly (mostly not set at all!). So potentially there is a real risk of combustion/ambient air and combustion gas mixing right there in the furnace! By the time this air and gas mixture reaches the oxygen sensor it no longer reflects true combustion conditions. For all practical purposes our expensive oxygen sensor is rendered worthless as the system now controls from a distorted reference and one most likely ends up with a control system suppressing air supply to an otherwise perfect fire to achieve set point oxygen levels. The very device which was meant to optimize efficiency now becomes its worst enemy.

I would also like to point out a number of lesser challenges facing an oxygen trim system:

1. A zirconium oxygen sensor has a limited service life of some 3 to 5 years, depending on the working environment. Even while lying in a bin in the store it deteriorates (although slowly) and may very well be expired by the time it is required to replace the one in service. Users of steam boilers often don’t know they are letting themselves in for high replacement and maintenance cost when installing oxygen trim systems.
2. The oxygen sensor needs to be cleaned and calibrated from time to time. Special tools and calibration gas is required to carry out calibration. Or it can be contracted out to a service contractor.
3. Setting up and tuning the oxygen trim control (PID) can be quite challenging, specifically when firing pea coal on a chain grate stoker. Unlike atomized fuels, coal is extremely slow (and often inconsistent) in its response to changes in the air-fuel ratio, which is often required with load fluctuations. For instance if the excess air is increased by say 10% it may take the combustion system up to 10 or 15 minutes before this change reflects to its fullest extent in an elevated flue gas oxygen level. Thus the challenge facing the control system boils down to “synchronizing” the rate of air-fuel ratio adjustment with the rate of response of the fire to adjusted excess air supply. If syncing is not performed accurately oxygen levels continuously overshoot or undershoot the target set point, especially if steam demand fluctuates significantly during a normal production day.

Then in closing:

1. I firmly believe that oxygen trim systems come to their right in combustion applications using atomized fuels, such as oil, gas and pulverized coal, where responses to changes in excess air are immediate and consistent. It is definitely not ideal for pea coal firing.
2. The challenges and demands facing users of steam boilers dictate that state of the art combustion control systems be employed. I am often surprised to find that new control systems are still being supplied and installed without incorporating the control, computing and communication power of plc’s. Optimizing combustion efficiency is sufficiently complex to warrant the use of computer technology in the operation and control of steam boilers.
3. In a recent development we have successfully tested a virtual oxygen sensor in a control system which uses the plc and special control logic to simulate oxygen trim control. Under normal operating conditions it delivers similar efficiency as oxygen trim control, but without the expense of purchasing, maintaining and replacing the otherwise required zirconium flue gas analyser.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.

In Boiler Bits 5 and Boiler Bits 6 we looked into the significance of excess air as an absolute necessity for proper combustion, and its role as the major contributor to boiler energy loss.

Imagine how convenient it will be to have an operational parameter which is representative of the percentage excess air of combustion, especially if this parameter can be used to control excess air accurately towards maximizing combustion efficiency. The good news is that such a parameter indeed exists and is being used in many combustion applications, not only with steam boiler operations, but also and in particular in the automotive industry.

As we have mentioned previously excess air does not actively take part in the combustion process and it does not give up any of its oxygen to combine with fuel atoms. It merely enters the furnace as ambient air and travels along through the system with the flue gas. But it leaves an oxygen footprint in the flue gas which tells us quite accurately the percentage excess air supplied to the combustion system.

Unknowingly many of us are using this oxygen footprint for excess air control on a daily basis. Getting behind the steering wheel of your fuel injected motor vehicle you are about to activate oxygen based combustion control which regulates the air and fuel mixture as part of the engine management system. A so called lambda sensor located in the exhaust gas stream continuously monitors the oxygen level of the combustion gas and by this means determines if the mixture is too lean (excessive excess air), or too rich (deficiency of excess air), or just right. It regulates the fuel injection system to continuously adjust the excess air (air-fuel ratio) to keep the engine performing at optimum levels of power, economy and emissions quality.

Well, why not use this technology to enhance boiler performance? Oxygen trim control is widely used with oil, gas and pulverized coal boilers. But how effectively does it perform with chain grate stokers firing pea coal fuel? In my dealings with users of steam boilers I often encounter widely differing responses to oxygen trim control for pea coal firing, ranging from ignorance and apathy to total awe at the perceived superior efficiency of this technology.

But first, back to the classroom. Let us assume that a combustion process firing pea coal requires 50% excess air for optimum combustion of the fuel. The stoichiometric air requirement for the relevant fuel feed is an arbitrary 100 units and a further 50 units of excess air are added, giving us a total combustion air supply of 150 units. The 100 units of stoichiometric air give up all of its oxygen in the combustion process and produce flue gas consisting of CO2 and nitrogen. The 50 units of excess air on the other hand pass through the system unchanged and exit the system containing 79% nitrogen and 21% oxygen on a volume basis. Thus on a volume basis the total flue gas mixture contains (50 units * 21%) = 10,5 units of oxygen. If we do a bit more number crunching (not shown here) we find that the 10,5 units of oxygen represent approximately 7% of the total volume of flue gas discharged through the stack. Or to sum it all up: 7% oxygen in the flue gas is indicative of 50% excess air. [Please note that this is a somewhat simplified approach, as the effects of hydrogen, moisture, sulphur, carbon monoxide, etc. are being ignored. But do not stress, we are not so much into the chemistry as into the principles of combustion and its control, as well as of its practical application.]

This relationship between excess air and flue gas oxygen is a very handy one to know. It means that if the oxygen content of the flue gas can be measured and controlled, the excess air percentage can also be controlled to provide for optimized air-fuel ratios, provided of course one knows the optimum excess air requirement of the fuel being burned.

A well designed combustion control system will often incorporate a flue gas analyzer (oxygen sensor/transducer) to accurately adjust (trim) the combustion air supply in accordance with the fuel feed rate. Theoretically then oxygen trim should enable one to operate the boiler at best efficiency under all load conditions.

But is this a practical reality? Maybe it is easier said than done? In our next edition of Boiler Bits I will explore the Achilles heel of oxygen trim control in greater detail.

This post was compiled by René le Roux for Le Roux Combustion, all rights reserved. Do you want to know more about combustion control systems and combustion optimization? Please contact us for your professional boiler automation, steam system efficiency and coal characterization needs.

Kindly note that our posts do not constitute professional advice and the comments, opinions and conclusions drawn from this post must be evaluated and implemented with discretion by our readers at their own risk.