09560 Sherik Caetano

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Thermodynamic Analysis of Formation of Black Powder in Sales GasPipelines

Abdelmounam SherikResearch & Development Center, P.O. Box 62, Saudi Aramco

Dhahran 31311, Saudi ArabiaE-mail:[email protected]

Boyd R. DavisKingston Process Metallurgy Inc., Kingston, ON CANADA K7P 1S6

E-mail: [email protected]

ABSTRACT

The product of reactions between steel pipelines and some species in processed natural

gas is a significant concern to the gas industry. The corrosion product, which is a mix of iron

oxides, sulphides, and carbonates, has several impacts on pipeline operations and must be

periodically removed by pigging the pipeline. The difficulty in understanding the mechanisms

of formation of this material comes in large part from the non-uniform conditions, such as water

dew point, H2S, CO2 and O2 concentrations, in the pipeline.

This paper provides an evaluation of the application of chemical thermodynamics to the

formation of this material - what is commonly known in the gas industry as black powder.

Given the complex nature of the formation of black powder, it was decided to study the

formation and stabilities of various iron phases, namely iron oxides, sulfides and carbonates as

well as elemental sulfur in sales gas pipeline environments.

Our findings show that thermodynamics can be a useful tool to indicate what can, and cannot,

possibly form under dewing conditions; however, compositional analysis of the powder can

assist in directing the calculations. Due to these uncertainties, the results should be used as a

guide to better understand the corrosion mechanisms inside the pipeline.

Keywords: black powder, computational thermodynamics, internal corrosion, Sales Gas,moisture content.

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INTRODUCTION

The product of reaction between the steel of natural gas pipelines and components in

processed natural gas is a significant concern to the gas industry. This corrosion product,

commonly referred to as black powder, is a mix of iron oxides, sulphides, and carbonates and

causes wear in valves and must be periodically removed by pigging the pipelines 1-4. Black

powder samples collected from sales gas pipelines showed only the presence of iron oxidesand carbonates as can be seen in Table 14

The difficulty in understanding the mechanisms for formation of this material comes from the

non-uniform conditions in the pipeline. Water content and dew points, H2S and CO2

concentrations, and the presence of oxygen will all have a significant impact.

Since corrosion is anticipated to have occurred due to condensed water (liquid phase), the

dew points under several operating conditions were calculated to determine deleterious

conditions. Furthermore, the composition and pH of aqueous phases were calculated using

various assumptions. E-pH diagrams were then generated to determine what iron ion species

would be predominant in the aqueous environment. Preliminary mass balances were done tosupport the E-pH diagram calculations to ensure that proposed mechanisms were consistent.

One of the main challenges in the current thermodynamic analysis was understanding, in sales

gas with oxygen ingress, the predominance of iron oxide phases (magnetite-Fe3O4, and -

FeOOH) in the collected black powder knowing from the literature 5-7 that FeCO3 would be the

expected dominant species. This is reflective of the significant complexity of the corrosion

problem resulting from changing conditions in the gas phase (such as oxygen ingress or

changes in H2S, CO2 and/or H2O levels), the effect of kinetics on the reaction of pipeline steel

with the solution, and the subsequent conversion of reaction products in a dry environment (for

example conversion of FeCO3 to Fe3O4). An added complexity to the current analysis is that

the analyzed black powder samples do not represent black powder that have formed at well

defined conditions (specific location and time) in the pipeline. They instead represent samples

collected from the sum of black powder products that have formed at varying locations and

times along the pipeline (for example, water condensation might have occurred only at low

points and for a few hours during the winter season or oxygen ingress takes place at low

pressure points, etc). All this makes the possibility of correlating the results of the current

thermodynamic analysis with actual field X-ray diffraction results quite a difficult task. This

means that an attempt at quantitative analysis of the thermodynamics as they apply to the

formation of black powder could be misleading as a result of the wide range of potential

conditions and kinetic limitations on the reactions. However, thermodynamics can be a useful

tool to predict what can, and cannot, possibly form under dewing conditions.

The fact that there is a wide range of products (iron oxides, carbonates and elemental sulfur)

sampled from the pipelines indicates that this is not a homogeneous process that is controlled

by thermodynamics. In other words, if the gas phase is relatively constant, thermodynamics

would predict one stable phase for each of the non-metallic components in the gas phase (i.e.

S and C). The fact that there are all the above mentioned phases present means that there

are regions of kinetic control in the pipeline. However, thermodynamics can be a useful tool to

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amounts. A 1988 survey of 44 natural gas transmission pipeline companies in North Americaindicated that the gas quality specifications allowed maximum O2 concentrations ranging from0.01mol% to 0.1mol% with typical value of 0.02 mol%

6, 8. It has been shown that an oxygen

content of approximately 0.01 mol % has little effect on steel corrosion in the presence ofstagnant water inside sales gas transmission pipelines, while 0.1 mol % produces fairly highcorrosion rates6, 8. This again points to the difficulty in making a quantitative analysis of theentire system. As a general rule of thumb, it has been recommended that operators oftransmission pipelines should consider limiting maximum oxygen concentration of 10ppmv

(0.001 mol%)6, 8. It is important to understand that O2 due to air ingression in the gas will inreality, not be at equilibrium with the other gases in the methane stream due to the low kineticsof methane reacting with oxygen at the operating temperatures. Oxygen cannot exist(thermodynamically) in a reducing environment such as sales gas as indicated by reaction(1), since it would react with methane. If oxygen were at equilibrium with the methane, thepartial pressure of O2 would be undetectable in this reducing atmosphere, and CO2 and waterconcentrations would increase. (H2S would remain relatively unaffected). This means that theconditions indicated by the equilibrium gas composition (i.e. the Eh

*and pH of the water or the

equilibrium CO2 in the gas phase) will not reflect the true kinetically controlled situation.Therefore, any calculations or diagrams generated based on the gas phase equilibrium mustbe interpreted in light of the expected kinetics (i.e. that oxygen could remain in the system as a

kinetically stable gas phase).

Specific reactions in black powder production that are problematic with regards to theapplication of thermodynamics are outlined below.

The ramification of the kinetic barriers is that it is difficult to accurately predict the equilibriumaqueous phase. However, by suppressing reactions in the calculations that will not occur inthe pipeline, a reasonable estimate of the aqueous phase can be made. This allows for amuch more useful analysis of the iron reaction products, since E-pH diagrams can be studiedwith the knowledge of the aqueous phase chemistry.

Dew point determination

In order to demonstrate the validity of the calculations, the dew points were calculated for arange of conditions and are shown in the following figures. The operating temperature and

pressure range were 15-30C and 720-900 psig, respectively. Dew point calculations

considered both that the balance of the sales gas was N2 and CH4 (CH4/N2 = 15.67) or Ar for

purposes of the calculations. It was determined that pressure has the largest effect on dew

point, more than any other variable.

Calculations were performed to determine if dew point temperature change as a function ofcontaminant concentrations and pipeline pressure. Figure 1 shows the comparison betweenthe results obtained a commercially available software package and the dew point calculatedusing the alpha moisture system (http://www.dew-point.com/calculate.html ) dew pointcalculator. In all cases, the results are within about 2oC of each other. As expected, the

impurities (H2S and CO2) had no significant effect on the dew point while pipeline pressure and[H2O] significantly affect dew point temperature.

Point Calculations: Point calculations are thermodynamic calculations done to attempt to

simulate the conditions in the precipitated water in the pipeline. They are most effectively used

to identify reasonable ranges of pH or redox for EpH diagrams or to help better understand

*Eh refers to the redox potential E of the solution, usually the Y axis on the EpH diagram (sometimes called an Eh-pH

diagram).

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reaction mechanisms. All calculations are based on one liter of gas and are in units of moles.

The output from the thermodynamic model gives the equilibrium gas phase and the aqueous

condensed phase.

By changing the values of CO2, H2S, and O2, a range of values for pH, Eh, and aqueous

species concentrations can be obtained. The concentration of aqueous species is important

so that the EpH diagrams can be set to the correct values. Oxygen can be used in these

calculations because methane and nitrogen have been replaced with Ar. This condition

represents a sort of transient condition where O2 has ingressed into the pipeline but remainsas unreacted with methane due to kinetic constraints.

In this way, a grid was set up to see the impact of changing gas conditions on the Eh and pH

of the solution. The results of this (low and high CO2 content) are shown in Tables 4 and 5.

The water concentration was selected at a maximum value of 0.55 mg/l

These point calculations indicate that CO2 will buffer the aqueous solution to a pH of about 4

typical of carbonate solutions. The addition of H2S in a reducing environment has little impact

on pH. The presence of oxygen also naturally drives up the Eh value, so there is the potential

for localized increases of Eh along the pipeline due to oxygen ingress.

The fact that there are no pH conditions that would be above about 5 in line with the work bySridhar et al.5 which have a range of conditions used for their test with CO2 at 10 psi and all

conditions (except the one loaded with NaOH) show a pH around 5.

The results mentioned above reinforce the difficulties of studying the problem in isolation of its

surrounding. These relatively highly acidic pH conditions are not encountered in the pipeline.

The presence of iron in the system has a dramatic effect on the actual chemistry. The pH of

the system is normally found to be between 5 and 6.5 due to the reaction of CO2 with iron.

When iron is introduced into the calculation, FeCO3 precipitates and the pH increases to 5 and

FeOH+ is found in the aqueous solution. This is much more in line with the actual field

findings. The formation of Fe3O4 is thermodynamically possible but depends on the availability

of iron to the system (ratio of iron to gas phase). This could help to explain the range of

compounds found in the pipeline.

The progression of product formation can be studied by looking at the calculated reaction

products as iron is introduced into the system. In the presence of any Fe (given an oxygen

free system), FeS2 is the first iron compound to form (at around pH ~4). FeCO3 forms next if

the available sulphur is exhausted which will increase the pH to above 5. However, the

relative rates of these reactions are not known and are affected by the relative concentrations

of the gases. It has been stated in the literature that when CO2 and H2S are both present in

condensed moisture, the corrosion product that forms is a function of the partial pressure of

both acid gases and temperature. Several investigators have suggested different CO2/H2S

ratios, such as 200 and 500, which represent the change from predominately FeCO3 to FeS6.

It should be noted that the preference of CO2 forming carbonate over H2S forming FeS (both

reactants in aqueous form) is a kinetic phenomenon, and not based on thermodynamics.

Thermodynamically, iron will preferentially react with S than CO2 at virtually any concentration

of reactants. The fact that FeCO3 is found preferentially at high levels of CO2/H2S indicates

that the kinetic reaction for S is less than that for CO2 (perhaps due to a passivating film that

occurs with sulphur, or due, as mentioned above to exhaustion of S at the reaction site due to

the slow dissolution of more H2S into the water (slow replenishment of S in the water).

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As with CO2, the calculations involving S as described are also kinetically controlled. The

prediction of the formation of SO42- from thermodynamics is not what occurs in the field.

Reactions of oxygen and H2S appear to be kinetically slow and the preferential reaction is as

per the following reaction (2).

2 H2S + O2 = 2 H2O + 2S (2)

EpH Diagrams

EpH diagrams can be used to identify regions of pH and E (redox potential, or the oxidizing or

reducing environment of the solution). These diagrams are often presented in a series with

varying conditions of activity of one of the species. This is because, while EpH diagrams can

be constructed for metals in water, when a non-metallic element is introduced (in this case

carbon or sulphur) another degree of uncertainty is added to the system. This has to be

removed by setting the activity or partial pressure of a compound containing that non-metallic

element. However, providing a series of diagrams with no reference to the actual system has

little value in understanding the mechanism of reaction. For this reason, the point calculations

that were performed in this work are useful in helping to determine reasonable concentrations

of aqueous species for carbon and sulphur. As a baseline, the EpH diagram for water wasconstructed and is shown in Figure 2. FeOOH, the data for which was entered into the

commercial software package from literature8, was not shown to appear. Conditions for its

formation are not, at present clear, but it can be assumed that it forms in the presence of

oxygen via the following reactions (3).

2Fe + H2O(l) + 3/2 O2 = 2 FeOOH (3)

or through conversion of reaction products reactions (4) and (5):

4FeS + 2H2O + 3O2 = 4FeOOH + 4S (4)

Fe3O4 + 3/2 H2O + 1/4 O2 = 3 FeOOH (although likely kinetically limited) (5)

This diagram is at 15oC, although the effect of temperature is negligible over the range that is

experienced by the pipelines. The region of interest is between the two dashed lines. These

lines indicate the region where water is stable. It is clear that with only pure water and a basic

pH, it is possible to form Fe3O4 as shown by the region in Figure 2. The progression is from

elemental Fe, to FeO (or Fe(OH)2 as shown) to Fe3O4 and finally to Fe2O3 the most oxidized

iron oxide. If the aqueous species were to be removed from the diagram, it would show each

phase field layered on top of each other as the E(V) increases (becomes more oxidizing).

Influence of CO2 on the system: With the addition of CO2, the EpH diagram changes to that

shown in Figure 3 for a system with low CO2 in the gas phase (0.1 mol%). Here, because C is

added to the system, there must be a species selected that has a fixed concentration. This

can either be a gas (i.e. CO2) or aqueous species (i.e. HCO3-). HCO3

-was selected, and a

representative value was taken from the point calculations done in the last section.

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Note that the carbonate phase, FeCO3, is covered by the aqueous FeOH+ and Fe2+ fields.

This only indicates the ionic concentration in the system, since the diagram is set to the typical

10-6 concentration for the sum of ionic species (if the total of all ionic species is at least 10 -6,

the predominant ionic species will be shown on the plot). To see the solid phases, the ionic

species can be suppressed in the output, giving a result as shown in Figure 4. This plot

without aqueous species shown clearly demonstrates that FeCO3 is the significant phase in

the E and pH range that is of interest. This supports the point calculations showing that FeOH+

is present with CO2 and has an influence on the pH of the system.

Often, EpH diagrams are shown with the aqueous phase boundaries as dotted lines over the

top of the solid phases. The concentration of aqueous species over a phase field gives an

indication of the drive for corrosion, since corrosion will occur with greater intensity if the

dissolved Fe ions are able to build to a high concentration before equilibrium is reached. For

ease of discussion in this section, the concentration of aqueous species will be set at 0.001 so

that the solid phase fields may be seen with the aqueous species.

It is evident that Fe3O4 forms at pH values above about 6.5 but that the phase field overlaps

the FeCO3 for a given pH, depending on the Eh of the system. This could explain why both

FeCO3 and Fe3O4 are found in the black powder since a pH of 6.5 or greater is found in

laboratory tests at Saudi Aramco and it is reasonable that the Eh could change depending onthe availability of oxygen.

Influence of H2S on the system: The effect of H2S on the pipeline is highly dependent on the

atmosphere in the pipeline and kinetics as mentioned, oxygen does not react kinetically with

H2S to create sulphates. This means that EpH diagrams can vary widely as to the fields of

stability depending on the situation in the system. A simple EpH diagram using the pH2S as

the basis for the calculation yields the diagram in Figure 5. This shows Fe3O4 in between FeS

and FeS2. The Fe3O4 field is very narrow (and is only visible as a thicker line) but at lower H 2S

concentrations it is more predominate. This demonstrates that there is the likelihood for FeS

and FeS2 to form depending on the redox potential. Since oxygen ingression will affect theredox potential significantly, and oxygen ingression is a relatively non-uniform event

(sometimes minor, sometimes major) it is likely that both FeS and FeS2 will be found in a range

of concentrations with one another.

Both the case of CO2 and H2S demonstrate why a variety of solid material is found in black

powder. Oxygen ingress can widely vary the Eh of the system and favor the formation of one

compound over another. The nature of the ingress ranging in concentration and location

leads to this non-uniform residue and complicates the overall analysis of its formation.

CONCLUSIONS

It is clear from this analysis that internal corrosion of pipelines and black powder formation in

sales gas pipelines is a complex process that is not thermodynamically controlled however,

thermodynamics can assist with our understanding of the underlying chemical processes. The

fact that there is a wide range of products (iron oxides, iron carbonates and elemental sulfur)

sampled from the pipelines indicates that this is not a homogeneous process that may not be

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controlled by thermodynamics. These products are mainly due to: (1) intermittent ingress of

oxygen resulting from process upsets and (2) the cyclical wet-dry conditions resulting from

process upsets and seasonal temperature changes. This makes the attempt to correlate the

iron phases obtained at well defined thermodynamic conditions to the composition of the black

powder that has formed in the pipelines at varying conditions (thermodynamic and kinetic

controlled regions) a complex task. However, thermodynamics can be a useful tool to predict

what can, and cannot, possibly form using well defined conditions (the point conditions

provided by Saudi Aramco).

REFERENCES

1. A.M. Sherik, S.R. Zaidi, E.V. Tuzan and J. Perez, Black Powder in Gas TransmissionSystems, Corrosion NACE 2008, pp.

2. R.M, Baldwin, Black Powder in the Gas Industry-Sources, Characteristics and Treatment,GMRC, Report No.TA97-4, May 1998

3. A. M, Sherik, Black Powder in Sales Gas Transmission Pipelines, Saudi Aramco Journalof Technology, Fall issue, 2007, pp.2-10

4. A. M. Sherik, Effects of Simulated Pipeline Processes on Black Powder Formation in SalesGas Pipelines, Report No. DR-002/05-COR, April 2007

5. N. Sridhar, D. S. Dunn, A. M. Anderko, M. M. Lencka and H. U. Schutt, Effects of Waterand Gas Compositions on the Internal Corrosion of Gas Pipelines-Modeling andExperimental Studies, Corrosion, Vol.57, No.3, 2001, pp221-235

6. B. Kermani, J. Martin, and K. Esaklul, Materials Design Strategy: Effects of H2S/CO2Corrosion on Materials Selection, Corrosion NACEXPO2006, Paper No.06121, pp1-18

7. F. F. Lyle, Carbon Dioxide/Hydrogen Sulfide Corrosion Under Wet Low-Flow Gas PipelineConditions in the Presence of Bicarbonate, Chloride and oxygen, PRCI Final Report PR-15-9313.

8. J. Majzlan, K.-D. Grevel, and A. Navrotsky, Thermodynamics of Fe oxides: Part II.Enthalpies of formation and relative stability of goethite (-FeOOH), lepidocrocite (-FeOOH), and maghemite (-Fe2O3), American Minerologist, 88, 855-859, 2003

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Table 1

Composition of b lack powder as determined by XRD technique.

Main Compound Approximate averagewt%

Magnetite-Fe3O4 60-FeOOH Trace amounts (


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Table 4

Impact of changing gas concentrations on the aqueous phase(CO2 = 0.1 mol%, H2O = 0.55 mg/l, P = 720 psi, T = 15

oC)

H2S Concentration (ppm)O2 concentration(mol%) 0 2 6

Eh (V) pH Eh (V) pH Eh (V) pH

0 0.562 4.546 -0.003 4.283 -0.003 4.244

0.01 0.944 4.546 1.216 -0.205 1.237 -0.558

0.05 0.954 4.546 1.227 -0.205 1.248 -0.558

Table 5

Impact of changing gas concentrations on the aqueous phase(CO2 = 1.6 mol%, H2O = 0.55 mg/l, P = 720 psi, T = 15

oC)

H2S Concentration (ppm)O2 concentration(mol%) 0 2 6

Eh (V) pH Eh (V) pH Eh (V) pH

0 0.596 3.944 0.024 3.893 0.022 3.882

0.01 0.979 3.944 1.231 -0.204 1.252 -0.558

0.05 0.989 3.944 1.227 -0.204 1.248 -0.558

Water Concentration (mg/L)

0.0 0.1 0.2 0.3 0.4 0.5 0.6

DewP

oint(oC)

0

5

10

15

20

25

30

35

Fact 900 psi

Fact 720 psi

Internet 900 psi

Internet 720 psi

Figure 1 Calculated dew points as a function of pipeline pressure and two di fferentsoftware packages assuming ideal gas with Ar substitut ing N2 and CH4

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pH

0 2 4 6 8 10 12 14

E(V)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe(s)

Fe2+

Fe(OH)2(s)

FeOH+

T = 15oC

a(ions) = 10-6

Fe3+

Fe2O3(s)

Fe3O4(s)

Figure 2 E-pH diagram for Fe in water

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pH

0 2 4 6 8 10 12 14

E(V)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe(s)

Fe2+

FeOH+

T = 15oC

a(ions) = 10-6

Fe3+

Fe2O3(s)

Fe3O4(s)

Figure 3 E-pH diagram for Fe-C in water for low CO2 in gas phase

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pH

0 2 4 6 8 10 12 14

E(V)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe(s)

T = 15oC

[HCO3-] = 10

-5

no ions shown

Fe2O3(s)

Fe3O4(s)

FeCO3(s)

Figure 4 E-pH diagram for Fe-C in water for low CO2 in gas phase (no ionic speciesshown)

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pH

0 2 4 6 8 10 12 14

E(V)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe(s)

Fe2+

FeS(s)

FeOH+

T = 15oC

pH2S = 10-8

a(ions) = 10-6

Fe3O4(s)

FeS2(s)

Figure 5 E-pH diagram for Fe-S in water forpH2S = 10-8

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