getting the most out of your sulfur recovery unit ... · getting the most out of your sulfur...

Getting the Most Out of Your Sulfur Recovery Unit Performance Test

Richard J. Wissbaum Technology Director URS – Energy & Construction Michael Anderson Grand Pooh-bah Brimstone STS Limited

Presented at the 2012 Brimstone Sulfur Recovery Symposium

Vail, Colorado, September 11 – 14, 2012

ABSTRACT Measuring the performance of a sulfur recovery unit is a difficult task. It requires special sampling techniques, special sample handling techniques, and special analytical techniques. (This is why there are only a few companies in the world who perform this work.) It should, therefore, come as no surprise that special techniques are also required to analyze the raw data to obtain a clear snapshot of the performance of the facility. Because performance measurement is so difficult (that is, expensive), most companies obtain test data only on an as-needed basis. Therefore, it is important to extract the maximum amount of information from every performance test report. The purpose of this paper is to provide the facility engineer a few insights and simple tools to aid in that effort. In addition, we will examine a few examples – taken from actual performance test reports – illustrating the benefits of an independent analysis of the test results.

DISCLAIMER It is NOT the purpose of this paper to question the results reported by any of the various

companies who conduct performance tests on sulfur recovery facilities. The reports provided by these companies are consistently high in quality and beneficial to the user. However, as

engineers it is our job to collect and analyze data and to form our own conclusions based on that data. The methods presented in this paper are intended to allow the facility engineer to perform

his or her own analysis and to reach independent conclusions. Often, those conclusions will agree with the official report; occasionally, they may not agree. In either case, the

understanding of the actual performance of the facility will be improved.


INTRODUCTION Performance test reports often contain 50 – 100 pages, and even longer reports are commonly encountered. These reports are packed with raw data, analyzed data, general discussion and specific conclusions. It takes a considerable amount of effort to understand, and make use of, all of the information provided is these reports. Unfortunately, pressures of time and workload can result in only a cursory review of these reports. The process engineer assigned to the SRU (among his or her many other tasks) may have time to (a) read the Executive Summary and (b) scan the report and take note of items highlighted in bold text. (You know who you are!) However, these reports contain significantly more information than can be summarized and understood quickly. A thorough review of the report, including some simple analysis of the raw data and understanding the reasoning behind the report’s conclusions and recommendations, can lead to an improved understanding of the unit performance. It can also greatly increase the benefits obtained from the performance test work. Performance tests vary widely in their complexity. Some very simple tests – or “front-to-back” tests – consist of nothing more than acid gas and incinerator stack gas (or, alternately, SRU tail gas) analysis. These tests are performed simply to estimate sulfur recovery efficiency on an overall unit basis. Similar limited tests might be performed to determine extent of destruction of impurities (BTEX, ammonia, etc.) or formation of COS and CS2. Full performance tests can include sampling of every intermediate in the facility to allow evaluation of the performance of every reactor, reheater, condenser in the SRU (and, if present, the TGU). This paper will focus on the analysis of overall unit (as opposed to stage-by-stage) performance: either the SRU, or the SRU plus TGU. Since most performance test data provides incinerator stack gas composition, the incinerator is almost always included when analyzing the overall performance; however, this should not be taken to mean that the incinerator is the most important part of the unit. (In fact, the presence of the incinerator both complicates and simplifies the analysis, as we will see.)


PART 1 – ANALYTICAL METHODS Calculation of Sulfur Recovery Efficiency by the Carbon Balance Method

The Carbon Balance method – also called the C/S ratio method – compares the relative amounts of carbon and sulfur in the process stream as sulfur is removed (recovered) from the process. Surprisingly little information is required to calculate a good estimate of sulfur recovery efficiency. The equation is:

Efficiency = 1.0 – (Sd/Sa) · (Ca/Cd + Qf/Qa · Cf/Cd) + Qf/Qa · Sf/Sa Where:1

Q is the flow rate of the stream (in any consistent molar units); S is the sum of the sulfur atoms in the stream; C is the sum of the carbon atoms in the stream; The subscript ‘a’ refers to the combined acid gas stream; The subscript ‘f’ refers to the combined fuel gas stream; The subscript ‘d’ refers to the downstream effluent.

Example: Sulfur recovery unit ABC has two feeds: amine acid gas and SWS acid gas. Stream flow rates, compositions and conditions are given in the following table. Estimate the sulfur recovery using the carbon balance method. Amine Acid Gas SWS Acid Gas Fuel Gas Stack Gas

Hydrogen 1.005

Argon 1.018

Oxygen 2.559

Nitrogen 1.227 85.081

Methane 0.014 0.014 95.911 0.027

Carbon Monoxide 0.641

Carbon Dioxide 17.840 6.292 0.688 8.924

Ethylene 0.031 0.036

Ethane 0.013 0.006 2.048

Hydrogen Sulfide 81.827 44.880

Carbonyl Sulfide 0.004 0.022

Propane 0.143 0.134 0.097

Sulfur Dioxide 0.745

Butanes 0.041 0.129 0.022

Pentanes 0.065 0.613 0.007

Hexanes 0.022 0.492

Ammonia 47.382

TOTAL 100.000 100.000 100.000 100.000

Temperature, F 90 183

Pressure, psig 25.02 25.22

Flow, SCFH 221,100 34,925 16,400

1 This nomenclature is consistent with Paskall and Sames [1].


Step 1: Since flow rates are measured on a total basis (i.e. wet), we must first convert the acid gas compositions to wet basis, assuming the partial pressure of water in each stream is equal to the vapor pressure of water at the stream temperature. At the same time, we normalize the compositions. The fuel gas stream at this facility is dry. Step 2: Because the carbon balance method allows only one acid gas stream, we must blend the two acid gas feed streams into a combined acid gas stream, based on their relative flow rates and individual compositions. The table below shows the results of steps 1 and 2. Amine Acid Gas SWS Acid Gas Total Acid Gas

Hydrogen

Argon

Oxygen

Nitrogen

Methane 0.014 0.010 0.013

Carbon Monoxide

Carbon Dioxide 17.345 4.296 15.565

Ethylene 0.030 0.025 0.029

Ethane 0.013 0.004 0.011

Hydrogen Sulfide 79.555 30.646 72.883

Carbonyl Sulfide 0.004 0.015 0.005

Propane 0.139 0.092 0.133

Sulfur Dioxide

Butanes 0.040 0.088 0.046

Pentanes 0.063 0.419 0.112

Hexanes 0.021 0.336 0.064

Ammonia 32.354 4.414

Water 2.776 31.716 6.724

TOTAL 100.000 100.000 100.000

Flow Rate, SCFH 221,100 34,925 256,025

Step 3: Now compute the carbon and sulfur atom sums for acid gas, fuel gas, and stack gas. These sums are shown in the table on the next page.


Total Acid Gas Fuel Gas Stack Gas

Hydrogen 1.005

Argon 1.018

Oxygen 2.559

Nitrogen 1.227 85.081

Methane 0.013 95.911 0.027

Carbon Monoxide 0.641

Carbon Dioxide 15.565 0.688 8.924

Ethylene 0.029

Ethane 0.011 2.048

Hydrogen Sulfide 72.883

Carbonyl Sulfide 0.005

Propane 0.133 0.097


Butanes 0.046 0.022

Pentanes 0.112 0.007

Hexanes 0.064

Ammonia 4.414

Water 6.724

Carbon Sum 0.1719 1.0111 0.0959

Sulfur Sum 0.7289 0.0000 0.0075

Step 4: Now compute the recovery efficiency using the formula.2 Efficiency = 1.0 – (/) · (/ + 16400/256025 · /) +

16400/256025 · 0.0000/0.7289 Efficiency = 0.9748, or 97.48% sulfur recovery Comments on the Method Note that this method does not require measurement of either stack gas flow, or sulfur product flow. Note also that although we converted the acid gas and fuel gas streams to a wet basis (although the wet basis fuel composition in this example contained no water), we did not convert the stack gas composition to a wet basis. This apparent inconsistency is allowable, as demonstrated in the derivation of the formula in the next section. The derivation will also illustrate the inaccuracies in this method, namely: (1) this method ignores the CO2 content of the combustion air (normally about 390 ppm, or 0.0004 mole fraction), and (2) this method assumes that none of the sulfur contained in the fuel is recovered

2 Note that we use volumetric flow (in SCFH) instead of molar flow. Since this is a low pressure system, the gas is nearly ideal, and volumetric flow is related to molar flow by a constant (379.79 SCF/lb∙mol in English units.)


(which would be true if the only fuel use is in the incinerator). These assumptions mean that the calculated recovery will be inaccurate (although usually in just the fourth decimal place.) Derivation of the Method Assumptions: 1. One acid gas stream 2. One fuel gas stream 3. Ignore carbon in the combustion air 4. Assume no recovery of sulfur in fuel is possible Define the following streams: a is the acid gas stream, molar flow rate Qa f is the fuel gas stream, molar flow rate Qf d is the downstream effluent (e.g. stack gas) with unknown molar flow rate Define the following terms: The carbon sum (denoted C) is the sum, over all components in a stream, of the mole fraction of the component times the number of carbon atoms in that component. The sulfur sum (denoted S) is the sum, over all components in a stream, of the mole fraction of the component times the number of sulfur atoms in that component. We can now make the following statements: Atoms of Carbon entering the process:3 Qa · Ca + Qf · Cf Atoms of Sulfur entering the process:3 Qa · Sa + Qf · Sf Atoms of Carbon in the effluent:4 Qa · Ca + Qf · Cf = Qd · Cd Moles of dry gas in the effluent (Qd): (Qa · Ca + Qf · Cf ) / Cd Atoms of Sulfur in the effluent: Sd · (Qa · Ca + Qf · Cf ) / Cd Efficiency = 1 - (Atoms S in effluent – Atoms S in fuel) / (Atoms S in Acid Gas) = 1 - (Atoms S in effluent) + (Atoms S in fuel) (Atoms S in Acid Gas) (Atoms S in Acid Gas) = 1 - Sd · (Qa · Ca + Qf · Cf ) + Qf · Sf Cd · Qa · Sa Qa · Sa

3 Since flow rates are measured on a total (i.e. wet basis), the atom sums must be calculated on a wet basis. 4 Since there is no carbon or sulfur in water, the right hand side of the equation can be on a dry (i.e. water free) basis. This allows us to use the water free sample analysis. The calculated flow rate, Qd, is on a water free basis.


= 1 - Sd · (Ca + Qf · Cf ) + Qf · Sf Sa (Cd Qa · Cd) Qa · Sa Calculation of Sulfur Recovery by the Analytical Flow Ratio Method There is another method of calculating sulfur recovery which does not require the simplifying assumptions of the previous method, and which yields additional useful information as well. This method, which was developed by Harold Paskall, is called the Analytical Flow Ratio method, or AFR. The AFR method is based on atom balances around a generic sulfur recovery facility. A schematic of the generic facility is shown in Figure 1.

Figure 1 Generic Sulfur Recovery Facility

We can write five atom balances around this generic facility – one each for carbon, hydrogen, oxygen, nitrogen and sulfur. We then have the following system of equations: Q1·C1 + Q2·C2 + Q3·C3 = Q5·C5 + Q6·C6 + Q8·C8 Q1·H1 + Q2·H2 + Q3·H3 = Q5·H5 + Q6·H6 + Q8·H8 Q1·O1 + Q2·O2 + Q3·O3 = Q5·O5 + Q6·O6 + Q8·O8 Q1·N1 + Q2·N2 + Q3·N3 = Q5·N5 + Q6·N6 + Q8·N8 Q1·S1 + Q2·S2 + Q3·S3 = Q5·S5 + Q6·S6 + Q8·S8 The compositions (and therefore the atom sums) of air (stream 3), water (stream 5) and sulfur (stream 6) are all known. The compositions (and therefore the atom sums) of acid gas (stream 1), fuel gas (stream 2) and dry effluent (stream 8) are analyzed (although we must correct the compositions of acid gas and fuel gas to account for water, as before). Finally, Q1 and Q2 are known. The remaining unknowns are: Q3 (often unknown because many facilities have a natural draft incinerator), Q5, Q6 and Q8. We have a system of five equations with only four unknowns.

WET EFF (8+5)ACID GAS (1)

FUEL GAS (2)

AIR (3)

DRY EFF (8)

WATER (5)

SULFUR (6)

PARTIAL OR COMPLETE SULFUR

PLANT


Since we have more equations than unknowns, we can solve this system in either of two ways. First, we can ignore the known flow rate of fuel gas and calculate the fuel gas flow required to satisfy all five equations. This is called a Type I AFR. Alternately, we can ignore the nitrogen balance equation, solve for the unknown variables, and check the error in the nitrogen balance using the solution. This is called a Type II AFR. Example: Prepare a Type I and a Type II AFR balance using the data from the previous example. Steps 1 and 2 are the same as before: convert the acid gas and fuel gas stream compositions to wet basis and blend the acid gas feeds into a single stream. Step 3: Compute all five atom sums – carbon, hydrogen, oxygen, nitrogen and sulfur. The results are shown in the table below. (The composition of air has been converted to a wet basis using ambient temperature and humidity.) Total Acid Gas Fuel Gas Air Stack Gas

Hydrogen 1.005

Argon 0.929 1.018

Oxygen 20.819 2.559

Nitrogen 1.227 77.612 85.081

Methane 0.013 95.911 0.027

Carbon Monoxide 0.033 0.641

Carbon Dioxide 15.565 0.688 8.924

Ethylene 0.029

Ethane 0.011 2.048

Hydrogen Sulfide 72.883

Carbonyl Sulfide 0.005

Propane 0.133 0.097


Butanes 0.046 0.022

Pentanes 0.112 0.007

Hexanes 0.064

Ammonia 4.414

Water 6.724 0.607

Carbon Sum 0.1719 1.0111 0.0003 0.0959Hydrogen Sum 1.7646 3.9701 0.0121 0.0212Oxygen Sum 0.3786 0.0138 0.4231 0.2510Sulfur Sum 0.7289 0.0000 0.0000 0.0075Nitrogen Sum 0.0441 0.0245 1.5522 1.7016


Step 4: Formulate the five atom balances for a Type I AFR, grouping the unknown terms on the left side of the equation and the known terms on the right side of the equation, and eliminating terms with coefficients equal to zero: Carbon: -1.0111·Q2 – 0.0003·Q3 + 0.0959·Q8 = 256025·0.1719 Hydrogen: -3.9701·Q2 – 0.0121·Q3 + 2.0000·Q5 + 0.0212·Q8 = 256025·1.7646 Oxygen: -0.0138·Q2 – 0.4231·Q3 + 1.0000·Q5 + 0.2510·Q8 = 256025·0.3786 Sulfur: -0.0000·Q2 + 1.0000·Q6 + 0.0075·Q8 = 256025·0.7289 Nitrogen: -0.0245·Q2 – 1.5522·Q3 + 1.7016·Q8 = 256025·0.0441 After considerable manipulation (not for the faint hearted!) we arrive at the following result:5 Q2 = 101,655 Q3 = 1,675,188 Q5 = 421,589 Q6 = 175,169 (which is the ideal gas equivalent of the molar flow rate, 461.58 lb·mol/hr.) Q8 = 1,536,255 Comparing the calculated fuel gas volumetric rate (Q2) to the reported fuel gas rate of 16,400, we can see that there is a significant source of error in the data. Unfortunately, AFR does not tell us where the error lies – it only points out the existence and approximate magnitude of the error. We must use a different approach to try to determine where the error lies. Step 5: Formulate the four atom balances for a Type II AFR, again grouping the unknown terms on the left side of the equation and known terms on the right side, and eliminating terms with coefficients equal to zero: Carbon: – 0.0003·Q3 + 0.0959·Q8 = 256025·0.1719 + 16400·1.0111 Hydrogen: – 0.0121·Q3 + 2.0000·Q5 + 0.0212·Q8 = 256025·1.7646 + 16400·3.9701 Oxygen: – 0.4231·Q3 + 1.0000·Q5 + 0.2510·Q8 = 256025·0.3786 + 16400·0.0138 Sulfur: + 1.0000·Q6 + 0.0075·Q8 = 256025·0.7289 + 16400·0.0000 Solving the system of equations as before, we arrive at the following result: Q3 = 752,384 Q5 = 256,297 Q6 = 181,888 (which is the ideal gas equivalent of the molar flow rate, 479.28 lb·mol/hr.) Q8 = 634,365

5 It turns out that the matrix is less prone to accumulated roundoff errors if we divide all equations by Q1. In actuality, we are solving for Q2/Q1, Q3/Q1, etc. Thus the name Analytical Flow Ratio.


Substituting these values into the nitrogen balance equation gives the following results: N in: 3107.18 lb·mol/hr N out: 2844.40 lb·mol/hr Error: 8.5 percent This is a more reasonable result. The calculated air flow of 752,000 SCFH compares well with the measured air flow (SRU + Incinerator) of 784,600 SCFH. Knowing molar flows of all streams, we can now calculate sulfur recovery efficiency very easily: Type I AFR: Sulfur in = 0.7289·256025/379.5 = 491.74 Sulfur out = 461.58

Recovery = 461.58 / 491.74 = 93.87 percent Type II AFR: Sulfur in = 0.7289·256025/379.5 = 491.74 Sulfur out = 479.28 Recovery = 479.28 / 491.74 = 97.47 percent Note that the Type II AFR recovery matches the carbon balance recovery very closely. This is because the carbon balance method used the measured fuel gas flow rate. Comments on the Method The AFR method provides not only a more accurate calculation of sulfur recovery, but also an indication of the consistency of the data. As seen above, use of the carbon balance method will provide an estimate of recovery efficiency, but will not expose any problems that may exist in the data. The AFR method is easily extended to account for different feed streams such as external hydrogen to the TGU, or fuel gas streams of different composition. The composition and flow rates of these additional streams must be known; this will simply be an additional contribution to the right hand side of the equations. So far, we have focused only on overall performance. But thorough performance testing – which includes compositions of the process stream throughout the unit – provides enough data to perform stage-by-stage AFR balances, calculating required air flow at each point in the process. Since each stage of the Claus unit can be compared to the previous stage, the calculated air flows should be consistent. This lends considerable credence to the data set as a whole.


PART 2 – SOFTWARE TOOLS As noted above, solution of five simultaneous equations by manual methods is not a task to be undertaken lightly. Therefore, Brimstone and URS have collaborated to make an Excel spreadsheet available which will automate most of the process. The spreadsheet is available in two versions – one for English units and one for metric units.6

DISCLAIMER: The spreadsheets described below have been developed and verified with the level of care customary within the industry. However, neither the Author, nor URS Corporation,

nor Brimstone STS Ltd. assume any liability whatsoever for any errors contained within the spreadsheet, nor for any misuse of the spreadsheet.

The spreadsheet contains Visual Basic code which solves the simultaneous equations. Therefore, Excel will do one of the following when you open the spreadsheet: (a) it might silently disable all Visual Basic code, rendering the spreadsheet non-functional, or (b) it might prompt you with an unobtrusive warning, like this:

If you plan to use the spreadsheet routinely, you should copy it into a separate folder, and designate all files within that folder as trusted. This will cause Excel to open the spreadsheet with full macro functionality every time. The spreadsheet contains six worksheets, as follows: Air Composition Which allows you to enter air conditions of ambient temperature, pressure

and relative humidity. Stream Analyses Which allows you to enter analytical data, normalize the data, and add

water to saturate acid gas streams. Recoveries Which summarizes sulfur recovery by the carbon balance method and by

both AFR methods. This sheet also provides the command button to solve the AFR matrices.

6 Scholars of engineering have been known to disagree violently about what constitutes a “metric” set of units. I refuse to enter into this debate. If the units provided are not suitable, you may easily change to different units.


AFR Matrix Which collects the matrix coefficients for both the Type I and Type II AFR methods and stores the solutions. DO NOT insert or delete any cells, columns or rows in this sheet. The Visual Basic macros read and write to specific row/column locations on this sheet.

Type I Balance Which presents the results of the Type I AFR balance, along with calculated recovery efficiency and fuel gas flow error.

Type II Balance Which presents the results of the Type II AFR balance, along with calculated recovery efficiency and nitrogen balance error.

The spreadsheets are not protected in any way: you may insert or delete rows, columns and cells (however, you are strongly advised not to do so: the Visual Basic code reads and writes cell contents by absolute location; shifting cell locations can cause the spreadsheet to stop functioning properly); you may modify formulas; you may even view and modify the Visual Basic code. However, this is quite a complicated spreadsheet and I do not recommend making changes unless you fully understand the workings of the spreadsheet. Values in cells are color coded: cells colored in dark blue text contain input values – feel free to change these values as desired. Cells colored in brown text contain default values which should be good for most situations – change these values if appropriate. Cells colored in black text contain the results of calculations – change these cells only if absolutely necessary. The Air Composition Worksheet This sheet provides the analysis of all combustion air streams. You should enter values for atmospheric pressure, ambient temperature and relative humidity. The spreadsheet will automatically estimate the vapor pressure of water based on ambient air temperature, correct that vapor pressure for relative humidity, and calculate the wet basis composition. The air composition is only used for AFR calculations, so you need not modify this worksheet at all if you are not performing an AFR analysis. Water vapor pressure is calculated by the IAPWS-97 engineering and scientific formulation. The formulation provided by IAPWS requires temperature in Kelvin and provides vapor pressure in MPa. The routines built into the worksheets have built-in units conversion. The English version assumes the input temperature is in degrees F and converts the output value to psia. The metric version assumes the input temperature is in degrees C and converts the output value to kPa. The Stream Analyses Worksheet This worksheet is used to enter the analytical data from the test program. Space is provided to enter the sample date and time to avoid confusion. Space is provided to enter two different fuel compositions (some facilities use different fuel in the SRU/TGU than in the incinerator) and to enter both tail gas (i.e. effluent from the SRU, or even a process stream somewhere within the SRU) and stack gas compositions.


This worksheet also saturates the acid gas streams based on stream temperature, pressure, and calculated water vapor pressure (calculated as described above). The worksheet also normalizes all compositions. The Recoveries Worksheet This worksheet is used to enter stream flow rates. Volumetric flow rates are converted to molar flow rates – the calculated molar flow rates are used as the Qn coefficients in all calculations. This worksheet also computes all atom sums used in both the carbon balance method and in the AFR methods. Sulfur recovery by the carbon balance method is calculated based on the tail gas composition (if provided) and on the stack gas composition (if provided). Sulfur recovery by both AFR methods is also shown on this worksheet for comparison with the recoveries calculated by carbon balance. The values shown are not updated automatically (the matrix solution is only performed when you click the “Solve” button). The spreadsheet automatically prepares AFR balances for both the tail gas composition or the stack gas composition, unless one or the other is missing. Note that a Type I AFR balance is not provided based on tail gas composition.7 The AFR Matrix Worksheet This worksheet is provided to allow you to examine the AFR matrix and the solutions. The coefficients for the Type I matrix (using stack gas) are in cells C7 through G11; the RHS for the Type I matrix is in cells H7 through H11. The solution vector is in cells C16 through G16. The coefficients for the Type II matrix (using stack gas) are in cells D7 through G10; the RHS for the Type II matrix is in cells I7 through I10. The solution vector is in cells D22 through G22. The coefficients for the modified Type II matrix (using tail gas) are in cells D30 through G33; the RHS for this matrix is in cells I30 through I33. The solution vector is in cells D38 through G38. Checks of the solution of the system of equations are provided in columns J and K: these values should all be zero. If there is a non-zero value, chances are you have changed the input and not yet clicked the “Solve” button on the Recoveries worksheet.8

7 This is because the Type I AFR calculates the fuel gas flow rate; but since any fuel burned in the SRU or TGU is included as “SRU Fuel Gas”, it is blended into the combined acid gas feed stream and sulfur contained in this fuel is counted in the recovery calculation.

8 If, for example, a tail gas composition is not provided, the spreadsheet will not attempt to solve the Type II matrix using tail gas as stream 8. In that case, the solution check values for that matrix will almost certainly be non‐zero. These are “leftover” values and may safely be ignored.


The Type I Balance Worksheet This worksheet presents a stream-by-stream mole balance based on the Type I AFR solution. Since this solution forces all atom balances, this tabulation will provide an overall mass balance. However, the fuel gas flow will vary from the measured fuel gas flow by the indicated error. The Type II Balance Worksheet

This worksheet presents stream-by-stream mole balances based on the Type II AFR solution. Note that this tabulation may not provide an overall mass balance. The calculated error in the mass balance is shown on this sheet. One balance is provided based on stack gas analysis; the other balance is provided based on tail gas analysis. If you do not provide one of the analyses, the results shown for that case will be meaningless. The balances also report the nitrogen balance error (in the case of stack gas analysis) and hydrogen balance error (in the case of tail gas analysis.)9

9 I have found that discarding the hydrogen balance equation tends to provide overall better results in the case of Type II AFRs based on tail gas analyses. Small analytical errors resulting from the difficulty of quantifying the various sulfur species in SRU tail gas tend to magnify in the solution algorithm, leading to wildly inaccurate sulfur product stream flow rates.


PART 3 – REAL-WORLD EXAMPLES NOTE: The following examples have been taken from actual performance test reports prepared by sulfur testing companies. The analytical data are unchanged, and any quotes from the test report are verbatim. However, the stream rates have been scaled – sometimes up, and sometimes down – to avoid any possibility of identifying the facility under discussion. Example 1: Refinery SRU Performance Test The following analytical data were reported (zero values omitted for clarity): Acid Gas SRU Tail Gas Incin Fuel Gas Stack Gas

Hydrogen 2.095 37.792

Argon 0.944 0.976

Oxygen 7.882

Nitrogen 0.047 78.904 6.828 81.623

Methane 0.194 26.621

Carbon Monoxide 1.634 1.838 0.083

Carbon Dioxide 29.811 16.232 0.289 9.262

Ethane 0.260 20.770

Hydrogen Sulfide 68.057 0.144


Propane 0.765 3.507

Sulfur Dioxide 0.036 0.173

Carbon Disulfide 0.007

Butane 0.303 1.343

Pentane 0.045 1.012

Hexane 0.074

Benzene 0.055

Ammonia 0.386

Temperature, F 147

Pressure, Psia 24.7

Flow, SCFH 241,200

Reported recovery based on the tail gas analysis was 99.16% and recovery based on the stack gas analysis was 98.84%. Ambient air temperature was 52 °F. The report also noted the following:

1. Based on process simulator results, the measured SRU combustion air rate of 544,000 SCFH was estimated to be about 30% high;

2. Based on process simulator results, the measured SRU furnace temperature was estimated to be about 250 °F low;

3. Based on process simulation to match the measured incinerator temperature, the measured fuel gas flow to the incinerator was estimated to be about 50% high, and the measured air flow to the incinerator was estimated to be about 15% high.


By entering analytical data and ambient conditions into the spreadsheet, the following results are calculated (see Example1.xls for additional detail): Recovery based on tail gas analysis: 99.43% (99.16% was reported) Recovery based on stack gas analysis: 98.58% (98.84% was reported) The Type II AFR balances have mass balance errors on the order of 0.1 percent. This tends to confirm the validity of the raw data. The Type I AFR balance shows a fuel gas flow error of -9 percent; that is, the calculated fuel gas flow is 9% higher than measured. The report indicated the calculated fuel flow was 30% lower than measured. The Type II AFR balance based on SRU tail gas calculates an SRU combustion air flow of 414,000 SCFH – about 25% less than measured. This is consistent with the report. Comparing the Type II AFR balances based on stack gas and on tail gas allows us to infer an incinerator air flow rate of about 790,000 SCFH. Measured total air flow was about 760,000 SCFH. This seems to confirm the measured flow rate. Blais et. al. [3] noted that reaction furnace heat loss effects can be significant, especially in smaller units or in units operating at extreme turndown. It seems likely that the report assumed optimistically low heat losses from the incinerator, leading to lower calculated fuel and air flow rates to achieve the measured temperature. (Heat loss effects in the incinerator can be huge and must be thoroughly understood.) This would lead to an erroneous conclusion that measured flows were too high. See the table below.

Comparison of Measured and Calculated Incinerator Air and Fuel Flows

Measured By AFR ReportedFuel Gas Flow, SCFH 38,500 42,000 25,500Incinerator Air Flow, SCFH 760,000 790,000 660,000


Example 2: Gas Plant SRU/TGU Performance Test The following analytical data were reported (zero values omitted for clarity): Combined Acid

Gas SRU Tail Gas TGU Recycle

Gas Incin Fuel Gas Stack Gas

Hydrogen 2.971 0.389

Argon 1.027 1.050

Oxygen 2.116

Nitrogen 85.865 0.136 1.144 87.850

Methane 1.033 97.816 0.057

Carbon Monoxide 1.199 0.102

Carbon Dioxide 13.325 7.982 43.277 1.013 8.407

Ethane 0.026



Propane 0.011

Sulfur Dioxide 0.355 0.027

Carbon Disulfide 0.044


Pressure, Psia 27.8 26.8

Flow, SCFH 378,800

Reported recovery of the SRU was 97.0% and recovery of the SRU+TGU was 99.93%. Ambient air temperature was 33 °F. Note that neither fuel gas flow nor recycle gas flow was available. (Where possible, testing protocols should include recording both fresh acid gas flow and combined acid gas flow in such cases, to allow a reasonable estimate of recycle gas flow.) Lacking both the fuel gas and the recycle gas flow rates makes analysis of the data difficult. There are three possible strategies to employ:

1. Use a calculated fuel gas flow, either from the report or from a separate incinerator simulation, and use a Type I AFR to calculate the TGU recycle flow which satisfies all atom balances. There are two disadvantages to this strategy: (1) as seen in Example 1, fuel gas flows calculated by simulation can be very error prone if incinerator heat loss effects are significant; and (2) the spreadsheet model is not configured to allow calculation of the TGU recycle flow by AFR. (However, this modification is possible for a person skilled in Excel.)

2. Assume a TGU recycle flow rate and perform a Type I AFR to calculate the fuel gas flow. Adjust the assumed recycle flow rate until a satisfactory nitrogen balance is achieved using the Type II AFR. The disadvantage to this strategy is that the recycle stream is such a small fraction of the overall mass balance that the results of the Type II AFR balance are very insensitive to the recycle flow rate. If the data is not very consistent, a wildly unlikely flow rate might be required to achieve overall atom balances.


3. Use the reported recoveries for the SRU and for the STU+TGU to estimate the recycle gas flow rate. This strategy has the disadvantage that it will not be possible to arrive at an independent check on the SRU+TGU combined recovery. (It will be possible to check the SRU recovery using the tail gas analysis.) However, this is almost always the best strategy to follow.

Using strategy 3, we estimate TGU recycle flow using the following procedure:

A. Calculate the fractions of combined H2S feed contributed by acid gas and recycle gas as follows: Acid gas fraction = 1.0 / (0.9993 / 0.970) = 97.07% Recycle gas fraction = 100 – 97.07 = 3.03%

B. Using the spreadsheet, determine number of moles of H2S in combined acid gas feed: Combined feed molar flow (wet basis) = 378800 / 379.79 = 997.39 lb·mol/hr Combined feed H2S concentration (wet basis) = 0.82374 Moles H2S in feed = 997.39 · 0.82374 = 821.59 lb·mol/hr

C. Now calculate molar flow of TGU recycle gas: TGU Recycle H2S concentration (wet basis) = 0.53005 TGU Recycle molar flow rate = 821.59 · 0.0303 / 0.53005 = 47.0 lb·mol/hr

Now use the calculated flow of 47 lb·mol/hr (or 17,850 SCFH) to calculate the fuel gas flow using the Type I AFR. The calculated flow is 76,200 SCFH, or 200.6 lb·mol/hr. The Type II AFR nitrogen balance error and the mass balance error are tabulated below for this case (and for ±20% cases, to demonstrate the insensitivity to recycle flow rate) in the table below.

Type II AFR Results at Varying TGU Recycle Flow Rates

Flow Rate, SCFH Fuel Flow, SCFH N2 Balance Error Mass Balance Error

14,300 71,400 0.00 0.0217,850 76,200 ‐0.01 0.0221,400 81,100 0.00 0.02

The report calculated a fuel gas firing rate of 11,400 SCFH – 15% of the rate calculated by the Type I AFR. This large discrepancy could indicate some inconsistencies in the data. The fuel gas rate should be checked against the data sheet or against a simulation. (Using the reported fuel gas rate results in a -20% nitrogen balance error and a 10% mass balance error.) Based on the SRU tail gas analysis, the spreadsheet calculates SRU recovery at 98.2% (versus 97.0% reported). The overall SRU+TGU recovery is 99.88% (versus 99.93% reported.)


Example 3: When Data Goes Wild If the performance test data is inaccurate or inconsistent, we might obtain some very surprising results. Consider the following example: The performance test of a sub-dewpoint sulfur recovery unit reported the following analytical data (zero values omitted for clarity): Amine Acid Gas SWS Acid Gas Fuel Gas Stack Gas

Hydrogen 51.84

Argon 1.05

Oxygen 2.63

Nitrogen 3.77 2.55 87.65

Methane 0.02 0.02 30.51

Carbon Monoxide 0.01 0.02 4.51

Carbon Dioxide 1.80 0.32 0.32 3.98

Ethylene 10.98

Ethane 0.03 0.02 0.21


Propane 0.08 0.05 2.12

Sulfur Dioxide 0.17

Butanes 0.03 0.05 0.87

Pentanes 0.01 0.07 0.14

Hexanes 0.06 0.44

Ammonia 35.53

TOTAL 100.01 100.00 99.99 99.99


Pressure, Psia 20.8 27.7

Flow, SCFH 19,673 3,700 2,457

The carbon balance method gives a calculated sulfur recovery efficiency of 99.8% (these samples were taken during the adsorb-adsorb portion of the cycle.) This agreed closely with the expected recovery. However, the Type I AFR calculated a fuel gas flow of 24,885 SCFH – ten times the recorded flow rate. If that fuel gas flow rate was correct, the sulfur recovery was closer to 98.2%. Further, the Type II AFR – using the recorded fuel gas flow rate – had a nitrogen balance error of nearly 60%; more nitrogen was entering the unit than was leaving the unit. The mass balance error was over 30%. Clearly, either the reported analyses were not consistent with each other, or one or more flow rates were incorrect. Although the AFR methods will normally detect – and, to an extent, quantify – such data errors, they will not provide any assistance in determining where the error lies. In this example, assuming the reported fuel gas flow rate is indeed off by a factor of ten leads to a very good Type II AFR nitrogen balance. Unfortunately, it also leads to an unreasonably high predicted incinerator temperature.


PART 4 – BEYOND THE AFR The Analytical Flow Ratio methods are powerful, but application over the years has revealed a few areas where additional analysis is required. Some of the deficiencies noted include: As seen in Example 2, the Type I AFR method can produce a fuel gas flow rate which is

wildly in error compared to the measured value. This is because the fuel gas stream usually represents a very small fraction of the overall mass balance; adjusting this flow to close the unit mass balance (which is, effectively, what the Type I AFR does) can result in large differences between calculated and measured fuel gas flow rates.

The Type II AFR forces the error into the nitrogen balance, which has the opposite effect: nitrogen accounts for more than 50% of the mass flow in air-only SRUs. Therefore, the Type II balance will diminish the apparent magnitude of data errors by “hiding” the error in the nitrogen balance.

As hinted by the footnote on page 15, the Type II AFR balance may be used to force the error into any of the five atom balances. Nitrogen is by far the most commonly used for the reason described in the previous bullet. Oxygen, hydrogen, carbon, or even sulfur, may be used instead. However, there does not seem to be any perfect solution which is applicable in all cases.

As a result, performance testing companies generally rely on additional analytical tools when they prepare performance test reports. Some companies document their approach very thoroughly; others provide less information. (However, all are willing to discuss their methods with their clients.) In 1996, Anderson [2] described a method which may be used to calculate the combustion air flow rate given only the acid gas feed composition and flow and the dry tail gas (or stack gas) composition. This method provides a quick check of measured combustion air flow rates, both in the SRU and in the TGU and Incinerator. It is readily implemented in an Excel spreadsheet and may be adapted to the extent of analytical speciation of hydrocarbons. (This method could – and should – be used in Example 1 to confirm the air flow rate as predicted by the Type II AFR.) However, when using an SRU tail gas composition for this analysis, the composition must be adjusted to include elemental sulfur (both vapor and entrained liquid) as described in the next section. The extra degree of freedom provided by the Type II AFR can be used in more creative ways than described in the third bullet above. As discussed earlier, using the Type II AFR and forcing all the error into the nitrogen can result in unacceptably large errors in the nitrogen balance. It turns out that if compounds other than nitrogen are allowed to float, overall material balance errors can be reduced. One testing company – Brimstone – creates a virtual stream, consisting of one or more real or imaginary compounds. This introduces an additional unknown: the flow rate of the virtual stream, which allows the use of all five atom balances in the solution. In addition to reducing the overall material balance error, this approach can help diagnose problems with the data set. By using different compounds in the virtual stream, sensitivity studies generally yields clues about the source or errors within the data set, including whether


those errors arise from analytical or process data issues. Based on experience, the compound that normally yields the smallest material balance error is CO2. Brimstone claims that when the flow rate of this virtual stream is less than 0.2 percent of the mass balance, the overall balance will be very satisfactory. (There are occasions when using compounds other than CO2 in the virtual stream will result in a mass balance with a smaller error.) As noted earlier, when intermediate stream compositions are known (as is typical during a full performance test), the AFR analysis may be repeated with successive downstream “effluent” streams as the outlet stream. Comparing the magnitude of the various virtual streams can help identify a specific unit operation within the unit where a significant material balance error occurs. (The software tool provided will not perform such a sophisticated analysis; however, the fundamental techniques are the same.)


PART 5 – MAKING SENSE OF IT ALL There are a few additional important items to note: 1. Correcting for Elemental Sulfur in SRU Tail Gas

Example 1 illustrated a significant difference – over a percent – between the sulfur recoveries calculated by SRU tail gas composition and by incinerator stack gas composition. None of the sulfur testing companies analyze for elemental sulfur in process gas streams, so SRU tail gas is always reported on an “elemental sulfur free” basis. In order to obtain a valid estimate of sulfur recovery based on SRU tail gas, you must adjust the composition to include elemental sulfur which is present (a) due to the vapor pressure of sulfur, and (b) due to entrainment of liquid sulfur. Lacking any other data, you can estimate the vapor pressure of sulfur using the following equation from Shuai and Meisen [4]:

ln(p) = 89.273 – 13463/T – 8.9643·ln(T) where p is pressure in Pascals and T is temperature in Kelvin.10 Liquid entrainment is usually on the order of 0.1 mole percent (wet basis), which is about 3 lbs/100 lb·moles of gas. The spreadsheet tool does not include these calculations; you may easily modify the “Stream Analyses” worksheet to incorporate them.

2. Issues with Incinerator Balances Incinerators can drive you crazy. As noted earlier, natural draft incinerators have no air flow measurement, and forced draft incinerators often have very poor air flow measurement. This makes it difficult to reconcile calculated combustion air flow with measured air flow. To make this harder, fuel gas flow metering at the incinerator is an issue at many facilities. Compared to other fuel users, this flow is minor and often receives little or no attention. Since this flow is a minor contributor to the overall mass balance, large errors in fuel flow rate will have only slight effects on the overall mass balance. To complete the problem, heat losses from incinerators are significant. A careful analysis of the mechanical design of the incinerator, as well as knowledge of where (and how!) temperature measurements are taken, is required to make even a rough estimate of

10 The same equation (in English units) is shown in the GPSA Engineering Data Book.


incinerator heat loss. This makes it difficult to properly incorporate heat balance information into the incinerator balance. Finally, attempts to measure stack gas flow (obtained, for example, as part of RATA tests) have been known to produce results that cannot possibly be reconciled with material balances obtained from performance testing. The reasons behind this are beyond the scope of this paper; it is mentioned simply as a precaution not to take the results of stack gas flow measurements too seriously. (Suffice to say that the rigorously formalized methods specified for this type of compliance testing are not always rigorously applied).

3. Accounting for Sulfur in Fuel Gas If the fuel gas contains significant sulfur, it must be properly accounted for in the calculation of sulfur recovery efficiency. The methods described (and the accompanying spreadsheet) ignore sulfur burned in the incinerator in the recovery calculations. If your facility burns sulfur-bearing fuel in the SRU (e.g. in-line heaters) or in the TGU (e.g. reducing gas generator), then it is likely that the sulfur contained in that fuel will be recovered and should be included in the recovery calculation. (However, the amount of fuel is likely too small to affect the calculation.) In order to use the spreadsheet, you should include SRU and TGU fuel gas in the “SRU/TGU Fuel Gas columns in the “Stream Analyses” and “Recoveries” worksheets. These fuel streams will be combined with the acid gas, causing that sulfur to be included in the sulfur recovery calculation.

4. Specific Balances around Individual Equipment As noted in the Introduction, the issue of estimating material balances around individual equipment items is beyond the scope of this paper. However, using the techniques described, it is possible (with sufficient compositional data) to perform successive balances starting with the waste heat boiler effluent and moving downstream, equipment item by equipment item. If this approach is attempted, we recommend using Brimstone’s “virtual stream” method, adding a stream with unknown flow rate but known composition. This allows you to specify fuel flow (which should be well known for fuels fired in the SRU and/or TGU) and solve all five atom balances. By tabulating the calculated flow rates of the virtual stream as you move farther and farther downstream in the unit, you should be able to identify significant data errors. These should be resolved appropriately before continuing downstream through the unit.


CONCLUSION Understanding the methods behind the calculation of sulfur recovery, and using the very powerful Analytical Flow Ratio methods (and variations on those methods), gives the engineer another tool to analyze sulfur recovery unit performance. Although it is tempting to fire up the process simulator and attempt to duplicate the test conditions, a few simple checks – such as the AFR balances – can quickly tell you if there is any hope of matching test flows and analyses. In Example 1 above, a simulation has a very good chance of matching the test data. After all, simulators force all five atom balances (along with a number of other constraints.) In Example 3, however, it seems likely that matching the test data with a simulator is a hopeless task. It is also tempting to accept the observations and recommendations in the official test report at face value. After all, these reports are prepared by skilled professionals. However, as shown in Example 1, the conclusions reached by the professionals might not always withstand close scrutiny. We certainly owe it to our employers to exercise our sound engineering judgment when acting on the recommendations of others.


REFERENCES 1. Paskall and Sames, Sulphur Recovery, Western Research, 1992.

2. Anderson, “A Method for Calculation of Claus Unit Sulfur Recovery Efficiency”, 1996 Brimstone Sulfur Symposium, September 26, 1996.

3. Blais, Marshall and Wissbaum, “How Hot is Your Reaction Furnace – Really?” 62nd Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, February 26 – 29, 2012.

4. Shuai and Meisen, “New correlations predict physical properties of elemental sulfur,” Oil and Gas Journal, October 16, 1995.

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