Combustion Equation - Air to Fuel Ratio / Gaseous Fuels

      Applications of the Combustion Equation

(1)          Stoichiometric proportions for finding the correct air supply rate for a fuel
(2)          Composition of the combustion products is useful during the design, 

               commissioning and routine maintenance of a boiler installation

On site measurements of flue gas composition and temperature are used as a basis for calculating the efficiency of the boiler at routine maintenance intervals.

   Combustion Air Requirements: Gaseous Fuels

Calculating the air required for gaseous fuels combustion is most convenient to work on a volumetric basis.The stoichiometric combustion reaction of methane is: 

CH₄ + 2O₂ → CO₂ + 2H₂O

which show that each volume (normally 1 m³) of methane requires 2 volumes of oxygen to complete its combustion.

•          If we ignore the components which are present in the parts per million range, air consists of about 0.9% by volume argon, 78.1% nitrogen and 20.9% oxygen (ignoring water vapor). Carbon dioxide is present at 0.038%.

•          For the purposes of combustion calculations the composition of air is approximated as a simple mixture of oxygen and nitrogen: oxygen 21% , nitrogen79%

•          The complete relationship for stoichiometric combustion:

CH₄ + 2O₂ + 7.52N₂ → CO₂ + 2H₂O +7.52N₂ 

       as the volume of nitrogen will be 2×79÷21=7.52.

•          A very small amount of nitrogen is oxidized but the resulting oxides of nitrogen (NO_X) are not formed in sufficient quantities to concern us here. However, they are highly significant in terms of air pollution.

•          It can be seen that the complete combustion of one volume of methane will require (2+7.52=9.52) volumes of air, so the stoichiometric air-to-fuel (A/F) ratio for methane is 9.52.

•          In practice it is impossible to obtain complete combustion under stoichiometric conditions. Incomplete combustion is a waste of energy and it leads to the formation of carbon monoxide, an extremely toxic gas, in the products.

      Excess air is expressed as a percentage increase over the stoichiometric requirement and is defined by: 

•   Excess air will always reduce the efficiency of a combustion system.

         It is sometimes convenient to use term excess air ratio, defined as:

Where sub-stoichiometric (fuel-rich) air-to-fuel ratios may be encountered, for instance, in the primary combustion zone of a low-NO_X burner, the equivalence ratio is often quoted. This is given by:  

Flue Gas Composition-Gaseous Fuels

•          The composition of the stoichiometric combustion products of methane is:

 1             volume CO₂
7.52        volumes  N₂
2              volumes H₂O

•          Given a total product volume, per volume of fuel burned, of 10.52 if water is in the vapor phase, or 8.52 if the water is condensed to a liquid.

The two cases are usually abbreviated to “wet” and “dry”.

•          The proportion of carbon dioxide in this mixture is therefore

•          The instruments used to measure the composition of flue gases remove water vapor from the mixture and hence give a dry reading, so the dry flue gas composition is usually of greater usefulness.     

                     

Considering the combustion of methane with 20% excess air, the excess air (0.2×9.52) of 1.9 volumes will appear in the flue gases as (0.21×1.9)=0.4 volumes of oxygen and (1.9-0.4)=1.5 volumes of nitrogen

•          The complete composition will be:

            constituent                        vol/vol methane
                CO₂                                        1
                O₂                                           0.4
                N₂                                           9.02
                H₂O                                        2

giving a total product volume of 12.42 (wet) or 10.42 (dry).

•          The resulting composition of the flue gases, expressed as percentage by volume, is:

       Constituent     % vol (dry)     % vol (wet)
                CO₂           9.6                     8.1
                O₂              3.8                    3.2
                N₂             86.6                  72.6
                H₂O           –                       16.1

•          Example :

A gas consists of 70% propane (C₃H₈) and 30% butane (C₄H₁₀) by volume. Find:

(a) The stoichiometric air-to-fuel ratio and
(b) The percentage excess air present if a dry analysis of the combustion products shows 9% CO₂ (assume complete combustion).

Solution:

The combustion reactions for propane and butane are

(a) Stoichiometric Air Requirement

On the basis of 1 volume of the fuel gas, the propane content requires 0.7 × (5 + 18.8) = 16.7 vols air and the butane requires0.3 × (6.5 + 24.5) = 6.3 vols air. Hence the stoichiometric air-to-fuel ratio is 23:1.

  

(b) Excess Air
                The combustion products (dry) will contain

                (0.7 × 3) + (0.3 × 4) = 3.3 vols CO₂
                (0.7 × 18.8) + (0.3 × 24.5) = 20.5 vols N₂

                plus υ volumes excess air, giving a total volume of products of (23.8 + υ ).

Given that the measured CO₂ in the products is 9%, we can write: 

•          hence   υ  = 12.87 vols

The stoichiometric air requirement is 23 vols so the percentage excess air is:  55.9 %

Calculation of Power Required For Pumping

Flow Rate , Q= 83.33 kg/sec

Density of Medium, l= 1000kg/m3

Pump Head Required, H= 25m

Pump Efficency, η=0.75

Pump Power Required, P = (Flow Rate *Required Pump Head)/(Efficiency) 

=(83.33*25)/0.75  =2777.667 kg m/sec  =37.00 hp

HCDP (HYDROCARBON DEW POINT)

Principles of Hydrocarbon Dew Point

Dew point is defined as the temperature at which vapor begins to condense. We see it in action every foggy morning. Air is cooled to its water dew point and the water starts condensing and collects into small droplets. We also see it demonstrated by a cold glass "sweating" on a humid day. The cold glass lowers the air temperature below the water dew point temperature and the water condenses on the sides of the cold glass. Water dew point is relatively simple and easy to predict since it is a single component system. It is easily removed using conventional techniques, primarily TEG (Triethylene Glycol) dehydration units.

Hydrocarbon dew point (HDP) is similar to the water dew point issue, except that we have a multi-component system. Natural gas typically contains many liquid hydrocarbon components with the heavier components found in smaller amounts than the lighter gaseous ends. It is the heaviest weight components that first condense and define the hydrocarbon dew point temperature of the gas. The dew point temperature also moves in relation to pressure.

One of the first questions we are asked by producers with a hydrocarbon dew point issue is:

"How can my hydrocarbon dew point be so high?"

By definition, a production separator separating oil from gas operates at vapor-liquid equilibrium. Therefore, the gas leaving the separator is in equilibrium with the oil. In other words, the gas leaving the separator is at its hydrocarbon dew point that equals the separator operating temperature (and pressure.) If the separator is operating at 100°F, then the gas has a 100°F dew point at separator pressure. As the gas leaves the separator and cools flowing through the piping system, liquids condense and the dew point decreases as the heavy ends condense. The TEG dehydration unit will remove some heavy hydrocarbons, in addition to water, and further reduce the hydrocarbon dew point. At the sales meter, (without a conditioning unit) the hydrocarbon dew point is usually close to the lowest temperature the gas has achieved on the location before it was sampled, at operating pressure.

Why Control Hydrocarbon Dew Point?

The gas transportation companies have come to the realization that managing hydrocarbon dew point reduces system liabilities, opens up new gas markets and generates operating revenue. By managing hydrocarbon dew point, hydrocarbon condensation can be prevented in cold spots under rivers and lakes where the liquids collect in the low areas and then often move as a slug through the system, over pressuring the pipe, and overpowering liquid handling facilities, flowing into compressors and end user sales points.

Most importantly, liquids in burners and pilots onsite and at end user locations, can cause fire and explosion hazards. Also, removing pipeline liquids helps prevent pipe corrosion in the low areas where water is trapped under the hydrocarbon liquid layer and slowly destroys the pipe integrity. Proper managing of gas dew point can also prevent liquids from forming as the gas cools while flowing through pressure reduction stations that feed end user supply systems. Controlling dew point is also necessary to qualify the pipeline to market gas to high efficiency gas turbine end users that require a dry and consistent quality fuel.

Specifications for HDP

Pipelines use two main methods to specify contractual natural gas hydrocarbon dew points.

1.     Limit on C5+ or C6+ components by analyzing for:

o    GPM (gallons of liquid per thousand SCF)

o    Mole %

2.     Specifying an actual HDP by:

o    Setting a hydrocarbon dew point temperature maximum at operating pressure

o    Setting a maximum cricondentherm hydrocarbon dew point

In addition, typical pipeline specifications or tariffs almost always specify a maximum GHV (Gross or Higher Heating Value), which is greatly affected by heavy hydrocarbons contained in the gas stream.

Cricondentherm Temperature

The cricondentherm temperature is the highest dew point temperature seen on a liquid-vapor curve for a specific gas composition over a range of pressure, e.g. 200-1400 psia. When you look at a hydrocarbon gas dew point temperature curve (phase envelope,) the curve bends with pressure. Shown below is a dew point curve, after conditioning, for a south Texas gas analysis. The transporting pipeline requires a 20°F cricondentherm temperature. At the time this sample was taken, the cold separator on the gas conditioning equipment was operating at 9°F and 875 psig.

Hydrocarbon Gas Dew Point Curve

The temperature shown in the HDP curve represents the gas dew point at the corresponding pressures.

A cricondentherm specification at first seems like the best way a pipeline can protect its assets. The transporting pipeline operator knows if it sets a cricondentherm temperature restriction below the lowest temperature seen in its system, it can raise and lower the gas pressure in the pipeline transportation system, and not have to worry about liquid condensation.

The problem a pipeline operator has in using a cricondentherm specification is in the calculation of the cricondentherm temperature. The cricondentherm temperature is calculated by obtaining an extended gas analysis and then inputting the analysis data into a software package, using equations of state to predict the dew point temperatures at the range of pressures.

However, many gas-transporting companies tend to collect gas composition data using on-line chromatographs or composite samples with a grouped C6+ component. The C6+ component does not provide any information on the heavier hydrocarbon (C7+) components that determine the gas hydrocarbon dew point. To calculate a cricondentherm the pipeline operator must make some assumptions. It is these assumptions that are causing problems. The pipeline operator must decide how to distribute the C6+ component for his calculation. The most commonly used distribution assumptions are the Daniels/El Paso distribution (i.e. 48% C6; 35% C7; 17% C8+) and the GPA distribution (i.e. 60% C6, 30% C7, 10% C8+).

Gas Processing- Rich/Lean Amine Loading

Rich/Lean Amine Loading - Amine loading, the amount of acid gases contained within a given amount of amine is critical in the operation, maintenance and performance of an amine plant.

Rich Amine Loading (RAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Contactor. This is typically represented in a mol ratio ((mol of CO2 + mol H2S)/mol amine). Generally speaking, this measurement is almost impossible to accurately measure in the field or in a lab so plant simulations are often times used to determine the RAL and adjust amine circulation rates and concentrations to meet desired results.

As RAL increases above a value of 0.40 mol AG/mol amine, several detrimental effects may be encountered  especially in an all CO2 acid gas system. These effects may include higher corrosion rates, higher temperature bulges within the Contactor and lower recovery of the acid gases due to slower reaction kinetics and capacity.

Thus, if the Rich Amine Loading exceeds recommended limits acid gas breakthrough may occur, process piping may erode/corrode (resulting in piping failures) and equipment may fail. For these reasons it is recommended employing stainless steel materials in the most critical areas of the plant.

Lean Amine Loading (LAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Regenerator and is measured in the same manner as the RAL described above. This is a much easier and more reliable measurement.

LAL values will vary, depending on the type of amine being used. For MEA which is one of the most corrosive amines a LAL of up to 0.15 mol/mol may be seen while in an MDEA system (one of the weakest and least corrosive amines) a LAL of 0.005 mol/mol is not uncommon.

Lean Amine Loading will be affected by the reboiler duty, reflux ratio and the number of fractionation stages within the Amine Still. If the lean amine is not properly maintained, the acid gases corrosion may be encountered in the hot portions of the plant specifically the Amine Still Reboiler and associated piping. Also if the LAL is too high, the ability of the amine to remove the acid gases from the inlet gas stream in the Amine Contactor may be diminished and product specifications may not be met. This is especially true of MDEA systems that try to meet a very low level H2S specification.

Therefore, when designing and operating an amine plant care should be given to making sure the system is large enough to avoid overloading the amine with acid gases (high RAL) and ensuring that the amine regenerator has sufficient capabilities to properly strip the acid gases from the amine (low LAL).

The Tank Blanketing Technique

Tank blanketing, also known to as tank padding, is the procedure of smearing a gas to the empty space in a storage tank or container (the term storage container refers to any container that is used to store products, regardless of its size). This techinique is used for a variety of reasons and typically involves using a buffer gas to protect products inside the storage container. Some of the benefits of blanketing include a longer life of the product in the container, reduced hazards, and longer equipment life.

Control board Pressure regulator Flow switch Magnetic level control Pressure / Vacuum Relief Valve

History

Appalachian Controls Environmental (ACE) in In 1970 was the first company to announce a tank blanketing valve. There are now many ready-made systems available for acquisition from a diversity of process equipment companies. It is also possible to piece together your own system using a variety of different equipment. Regardless of which method is used, the basic requirements are the same. There must be a way of allowing the blanketing gas into the system, and a way to vent the gas should the pressure get too high.

Since ACE introduced its valve many companies have engineered their own versions. Though many of the products available vary in features and applicability, the fundamental design is the same. When the pressure inside the tank drops below a set point, a valve opens and allows the blanketing gas to enter. Once the pressure reaches the set point, the valve closes, as simple as that.

As a safety feature, many systems include a pressure vent that opens when the pressure inside exceeds a maximum pressure set point. This helps to prevent the container from rupturing due to high pressure. Since most blanketing gas sources will provide gas at a much higher than desired pressure, a blanketing system will also use a pressure reducing valve to decrease the inlet pressure to the tank.

Practices

The most popular gas used in blanketing is nitrogen; it is widely used due to its inert properties, as well as its availability and low cost. This system is used for a diversity of products including cooking oils, flammable products, and pure water. These techniques also cover a wide variety of storage tanks, ranging from as large as a tank containing millions of liters of vegetable oil down to a quart-size container or smaller.

The use of an inert blanketing gas for food products helps to keeps oxygen levels low in and around the product because the product help to reduce the amount of oxidation that may occur, and increases shelf life. In the case of cooking oils, lipid oxidation can cause the oil to change its color, flavor, or aroma. It also decreases the nutrient levels in the food and can even generate toxic substances. Tank blanketing strategies are also implemented to prepare the product for transit (railcar or truck) and for final packaging before sealing the product.

When considering the application for flammable products, the greatest benefit is process safety. Since fuels require oxygen to combust, reduced oxygen content in the vapor space lowers the risk of unwanted combustion.

Tank blanketing is also used to keep contaminants out of a storage space. This is accomplished by creating positive pressure inside the container. This positive pressure ensures that if a leak should occur, the gas will leak out rather than having the contaminants infiltrate the container.