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The Carbon Dioxide/Hydrogen Sulfide Ratio -- Use and Relevance
Article in Materials performance · May 2015
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MATERIALS SELECTION & DESIGN
The Carbon Dioxide/Hydrogen
Sulfide Ratio—Use and Relevance
Stephen N. Smith, FNACE,
Corrosion and Materials Consultant,
The Woodlands, Texas
During the past decade, there has
been an increasing use of the assumption that there is a dividing line between carbon dioxide (CO2) and hydrogen sulfide (H2S) corrosion that is
determined by a CO2/H2S gas partial
pressure ratio of 500. Most users of
this ratio are not familiar with its origins, the assumptions it implies, or its
practical limits. This work investigates
the history and the basis for the ratio.
D
During the last 20 to 30 years, a greater
understanding has developed regarding
corrosion issues that exist in sour oil and
gas systems that contain both hydrogen
sulfide (H2S) and carbon dioxide (CO 2) vs.
the sweet systems that contain just CO 2.
Since even small additions of H 2S were
recognized as having an impact, guidance
was sought to help determine just how
much H 2S was required to turn a system
from sweet to sour. Often, a “rule of
thumb” ratio of 500 for the CO2/H2S partial
pressure has been utilized. This ratio is
widely quoted and appears in a number of
industry documents, but its origin and
technical basis do not seem to be well
documented.
There have been a number of documents over the last few years that have referenced a CO2/H2S ratio of 500 as the transition point between sweet and sour
corrosion. 1-2 The earliest identified mention of a value of 500 for the CO2/H2S ratio
was found in an article by Dunlop, Hassell,
and Rhodes3 that was presented at CORROSION/83. This was only eight years after the
original DeWaard and Milliams4 article on
2
MAY 2015 MATERIALS PERFORMANCE
CO2 corrosion in May 1975, so it seems reasonable to assume that an earlier origin
would not be likely. The topic of Dunlop’s
article was the fundamentals of sweet well
corrosion, not sour or even slightly sour
corrosion. The content of the article dealing with CO2/H2S is as follows:
Iron Carbonate—Iron Sulfide: Here, a
simpler order-of-magnitude guide is
proposed. From the values tabulated by
Latimer5 for the appropriate solubility
products and ionization constants,
coexistence of siderite and iron sulfide
(FeS) at 25 °C is indicated when the partial pressure ratio of CO 2/H 2S = 500.
Thus, by ignoring temperature effects
and solution imperfections, the conclusion is reached that siderite (iron carbonate [FeCO 3]) should prevail when
the partial pressure ratio CO2/H2S > 500;
when it is <500, FeS can be expected.
In order to re-derive Dunlop’s ratio of
500, it was necessary to obtain a copy of the
1938 version of Latimer’s publication in
order to use the same solubility products
and ionization constants. Assuming that
this was Dunlop’s only source of information, this was also the only way to determine exactly what values were used and
how the issue of gas solubility was handled.
The data available and the method that
was required to obtain a value of 500 are
shown in the appendix of the presentation
by Smith. 6 It is assumed that Dunlop
rounded the calculated value of 490 that
was derived up to the reported value of 500
since this was common practice among
engineers at that time, many of whom had
started out using log tables. Calculators
and desktop computers were still somewhat new in 1983.
NACE INTERNATIONAL: VOL. 54, NO. 5
Data Sensitivity
Temperature Effects
Dunlop stated that the ratio value of
500 was valid, “ignoring temperature
effects and solution imperfections.” There
is also a tacit assumption in the quality of
the thermodynamic data that was used.
Since Latimer’s data was so old, a new
set of thermodynamic data was used to
evaluate the effect that more modern data
would have upon the calculation. Since it is
preferable to use data from a single source
whenever possible to maintain consistency,
all data used for the comparison were from
Naumov 7 except that Berner’s 8 value for
mackinawite was used. When Latimer’s
values were replaced with the values from
Naumov that appear in Table 1, a ratio of
2070 is calculated instead of 490. Comparing the values in the table, there are minor
changes in the free energy values, but nothing that explained a four-fold increase in
the ratio.
At this point, a sensitivity analysis was
undertaken to better understand the sensitivity of the calculation to what seemed
to be minor changes in the thermodynamic input values. Dunlop’s calculations
were repeated using Latimer’s data, except that the free energy value for FeCO 3
was varied by up to 1%, a value that is still
larger than the value provided by Naumov.
No other input values were altered.
As seen in Figure 1, this minor reduction in one variable increased the calculated ratio from 490 to 7,462. The calculation is therefore extremely sensitive to
minor changes in the thermodynamic
input data. If these small fluctuations did
not occur equally in both the numerator
and denominator of the CO2 and H2S ratio
terms, then fluctuations of over several orders of magnitude in ratio could easily result. In most cases, the random nature of
variations between the eight thermodynamic values involved in the calculation
tends to diminish the magnitude of the
change in the ratio. However, any changes
that occur will still be magnified, so that
even small overall variations can create
significant deviations from 500.
The effect of temperature upon the
ratio was investigated since one of Dunlop’s
assumptions was that the temperature was
25 °C and that temperature effects would
be ignored. Naumov’s approach to modifying the thermodynamic values for reactions as a function of temperature was
used. The results of these calculations are
shown in Figure 2.
Since the calculations for Figure 2 used
Naumov’s data, the minor variations in values introduced by the temperature adjustment calculation combined with the sensitivity to the thermodynamic data has
reduced the starting point ratio at 25 °C
from 500 to 15. This is because the temperature compensation calculation required
additional thermodynamic inputs and the
increased number of input variables
increased the sensitivity to variations in
quality.
The resulting changes in the ratio as a
function of temperature when compared to
the variations that occur between thermodynamic data sets are minor within the
temperature range of 25 to 100 °C. The cal-
TABLE 1. THERMODYNAMIC
FREE ENERGY VALUES USED IN
EVALUATION
Species
∆G° Latimer
∆G°
Naumov
CO2vapor
–94,450
–94,255
H2CO3
–149,170
–148,940
HCO3–
–140,490
–140,260
CO
–126,390
–126,170
H2Svapor
–7,870
–7,955
H2Saqueous
–6,520
–6,660
2,950
2,880
23,420
20,500
2–
3
HS
–
S
2–
Fe
–20,310
–22,050
–161,260
–159,350
FeS
–22,900
–22,300
H2O
–56,690
–56,687
2+
FeCO3
culation was not extended beyond 120 °C
because Naumov’s extrapolation process
becomes progressively less reliable and
there are phase changes that start to occur
at the higher temperatures in some of the
FIGURE 1 Plot of calculated ratio as function of % reduction in ∆G FeCO3.
NACE INTERNATIONAL: VOL. 54, NO. 5
MATERIALS PERFORMANCE MAY 2015
3
MATERIALS SELECTION & DESIGN
compounds, such as FeS. These begin to
complicate the calculation.
Appropriate Use and
Relevance of the Ratio
FIGURE 2 Calculated effect of temperature upon the CO2/H2S ratio.
FIGURE 3 Relationship between oilfield corrosion products.9
4
MAY 2015 MATERIALS PERFORMANCE
Since the ratio calculation assumes the
coexistence of FeCO3 and the mackinawite
form of FeS, the conditions where the ratio
is valid is shown as Line 16 of Figure 3. At
the lower temperatures shown by Line 8,
the ratio calculation is not valid because
the equilibrium shown by this line involves
the equilibrium between Fe2+ and FeS corrosion products, not FeCO3-FeS. Although
it might be possible to extrapolate the ratio
for Line 16 to the range defined by Line 8
for rough guidance purposes, such actions
could be fraught with danger because other
considerations, such as pH and the total
dissolved solids, could introduce significant errors.
It should also be remembered that the
ratio calculation assumes that the form of
FeS that is precipitated is mackinawite.
This assumption is valid for low concentrations of H2S and temperatures below ~100
to 120 °C. At higher temperatures and concentrations of H2S, the form of FeS that is
produced will usually be either troilite or
pyrrhotite. Both of these compounds are
more thermodynamically stable. Changing
from mackinawite to pyrrhotite using Dunlop’s original calculation would mean that
the value of the ratio would need to be
adjusted from 500 to at least 2,500.
Appropriate use of the ratio therefore
requires the consideration of a number of
factors, such as:
• The sensitivity of the ratio to assumed thermodynamic inputs, which
can alter the calculated ratio to values as low as 9 to more than 2,600.
• Consideration of the production
conditions to determine whether
FeCO3 would form in the absence of
H 2S as opposed to Fe 2+ ions in solution. These conditions usually exist
for temperatures in excess of 65 °C or
where sufficiently high concentrations of bicarbonate exist in the produced water to exceed the supersaturation value for FeCO3.
NACE INTERNATIONAL: VOL. 54, NO. 5
The Carbon Dioxide/Hydrogen Sulfide Ratio—Use and Relevance
• Considerations of whether the type of
FeS that would form for conditions
below the calculated ratio would be
mackinawite or troilite/pyrrhotite.
For the higher temperature and
higher H 2S partial pressure conditions where troilite or pyrrhotite will
form, the value for the calculated
ratio would be much larger than
2,000 because the troilite and pyrrhotite of FeS are much more stable and
therefore require less H2S.
• Consideration of the assumptions
implicit in the calculation, such as a
temperature of 25 °C and a low ionicstrength produced water. The high
concentrations of dissolved solids
found in many oilfield produced
waters could alter the theoretical
ratio by changing the activity coefficients for the dissolved ions. The assumption of low ionic strength also
means that the effect of bicarbonates
from the reservoir or acetic acid is
not considered.
Conclusions
The origin of the value of 500 for the
CO2/H2S ratio appears to be covered in the
article by Dunlop, et al. Although the article did not provide an explanation for the
derivation of the value, the reference to Latimer did provide the information that was
required to develop a derivation of a ratio
value that was close enough to 500 to
believe that if Dunlop, et al. were not the
origin of the value, then at least they were
familiar with the source.
Although the ratio has historically provided a useful rule of thumb, it has a number of key assumptions, including a temperature of 25 °C and low ion-strength
aqueous solution. The impact of these
limiting assumptions is usually not con­
sidered.
Although Dunlop’s calculated ratio is
only valid at 25 °C, temperature was found
to have only a minor effect upon the ratio
within the range of 25 to 100 °C assuming
that the FeS corrosion product is mackinawite. Temperature increases beyond
100 °C were not investigated because of
NACE INTERNATIONAL: VOL. 54, NO. 5
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issues associated with potential phase
changes.
The ratio would have to increase if the
FeS corrosion product changes from mackinawite to pyrrhotite due to a change in
corrosion conditions. Using Latimer’s data,
the ratio would need to be increased from
500 to at least 2,500 just to account for the
change from mackinawite to pyrrhotite.
The ratio is also not applicable for the
lower temperature and low pH conditions
where Fe2+ is the likely corrosion product
rather than FeCO3.
Although there is a sound scientific
basis for the ratio, the error band produced
by variations in the thermodynamic data
inputs is so large as to make the ratio’s use
impractical as an engineering guideline.
Ratio values ranging from as low as 9 to as
high as 2,600 were calculated. However, a
change of only 1% to the FeCO3 free energy
increased the value to over 7,600. It is therefore far too sensitive to the specific thermodynamic input values to be of any practical
value beyond use as a very rough order of
magnitude guide.
The use of the CO2/H2S ratio as a rule of
thumb to determine sweet vs. sour corrosion conditions is recommended for use in
only the broadest of terms. The ratio is simply too sensitive to thermodynamic input
data quality to be a useful engineering tool.
Existing computer tools that model corrosion chemistry and can calculate FeCO 3
and FeS formation should be used whenever possible rather than reliance upon this
rule of thumb.
If a very quick evaluation is needed, use
of the ratio should be limited only to the
broadest of evaluations. Where ratios for
produced fluids result in values that are
below 1 or above 5,000, these conditions
might be considered to be sour or sweet,
respectively. Any ratio that is between 1 and
5,000 can only be considered to be questionable. For conditions that fall within the
questionable range, either laboratory testing or a comprehensive thermodynamic
modeling program should be used to determine whether the corrosion reactions will
be driven by sweet or sour chemistry.
References
1
R. Nyborg, “Guidelines for Prediction of
CO 2 Corrosion in Oil and Gas Production
Systems,” IFE/KR/E-2009/003, Sept. 2009.
2
NACE TG 305 Proposed Standard Practice,
“Wet Gas Internal Corrosion Direct Assessment Methodology for Pipelines,” Draft 5
(Houston, TX: NACE International, 2010).
3
A.K. Dunlop, H.L. Hassell, P.R. Rhodes, “Fundamental Considerations in Sweet Gas Well
Corrosion,” CORROSION/83, paper no. 46
(Houston, TX: NACE, 1983).
4
C. DeWaard, D.E. Milliams, “Carbonic Acid
Corrosion of Steel,” Corrosion 31, 5 (1974): pp.
177-181.
5
W.M. Latimer, Oxidation Potentials (New
York, NY: Prentice Hall, 1938).
6
S.N. Smith, “Discussion of the History and
Relevance of the CO 2/H 2S Ratio,” CORROSION 2011, paper no. 11065 (Houston, TX:
NACE, 2011).
7
G.B. Naumov, B.N. Ryzhenko, I.L. Khodakovsky, “Handbook of Thermodynamic
Data,” U.S.G.S. Report WRD-74-00 1, January
1974.
8
R.A. Berner, “Stability Fields of Iron Minerals
in Anaerobic Marine Sediments,” J. Geology
72 (1964): pp. 826‑834.
9
S.N. Smith, “A Proposed Mechanism for Corrosion in Slightly Sour Oil and Gas Production” (Houston, TX: International Corrosion
Congress, 1993).
This article is based on CORROSION 2011
paper no. 11065, presented in Houston, Texas.
STEPHEN N. SMITH, FNACE, is an independent consultant based in The Woodlands, Texas, e-mail: Stephen.Smith.PE@
gmail.com. He has an M.S. degree in metallurgical engineering from the University
of Texas at El Paso. A 41-year member of
NACE International, he is serving as NACE
Institute Policy and Practices Director, is a
NACE Fellow, and received a NACE Technical Achievement Award and Distinguished
Service Award. He is a Senior Research Fellow of the Institute of Corrosion and Multiphase Flow at Ohio University.
MATERIALS PERFORMANCE MAY 2015
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