The reliability of the software had been (and continues to be) evaluated using a series of diagnostic criteria by means of laboratory tests conducted for clients in different laboratories.
"was" or "is"
Might also give credit to Marshall Rafal
Might want to use the term "in-house work"
I am not yet happy with this section
Reading this paragraph shows we lost focused. i.e. The alkalinity must be evaluated but we wind up with comments about the bicarbonate.
You can't start a paragraph talking about H2S and then immediately drop the thought and talk abut CO2. These thoughts appear to be totally unrelated -
And then right back to H2S – they way you write this appears to be a string of unrelated thoughts.
The two scenarios you talk about below are already contained in this sentence.
Grammar!
Brent, this is the crux of the whole thing The way the H2S partial pressure is derived from the oil is entirely different from the way it is derived from the water.
I am confused now – cracking is being discussed below??????
I am not sure this is really what you want to say. What we said, I believe, is that the mol fraction of CO2 (or H2S) in the total fluid stream composition can not be taken as the mol fraction of the gas phase (or virtual gas phase)
Let's not equate "solubility" with "concentration". These terms are rigorously defined – we don't have to do the same nonsense other people ar doing. The solubility of Sodum chloride is 357 g/L. The concentration is what one has in solution after a certain amount of NaCl has been added.
Type equation here.No this statement is wrong. The part6itioning of CO2 or H2S between oil and water phases is not controlled by Henry's law – absolutely not. It is a different phenomenon.
Again, there is no sequitur to these two sentences.
There is no gas when system is single phase.
This has to be more detailed. How was the partial pressure arrived at for a given concentration in the brine.
Same comment
There is no rational for this.
Is this the right terminology?
All of a sudden the H2S concentration takes center stage to corrosion rate determination. I thought corrosion rates were the main objective.
This is ass backwards: The partial pressure is constant in the system – the concentration decreases with temperature
It's on the server under NACE 2013 conference.
I believe we should identify where the 5 ppm H2S are. Oil, Gas, Water????
Above it was 5 ppm here is 0.5 psi – we should be more consistent.
grammar
A Methodology to Calculate Acid Gas Partial Pressures for Reservoirs Above the Bubble Point Pressure for Material Selection Applications
Brent W.A. Sherar, Rudolf H. Hausler, Mario Guerra, and Ravi M. Krishnamurthy
Blade Energy Partners, Ltd.
16225 Park Row, Suite 450
Houston, TX, 77084
United States
ABSTRACT
The selection of materials for oil field tubulars requires detailed knowledge of the well environment in order to properly evaluate corrosion and cracking threats. Applicable material standards have specifications for brine composition (particularly the in situ pH and chloride concentration), the acid gas composition (e.g., H2S and CO2 partial pressures), the downhole temperature, and the total pressure. A problem arises when the fluids under downhole conditions are above the bubble point, and no gas phase exists from which the relevant partial pressures can be extracted. These are conditions where the entire gas phase, including the CO2 and H2S, is dissolved in the liquid phase. In this case, appropriate PVT models must be used to determine the partitioning of the acid gases between the formation brine and oil phase. The resulting acid gas concentrations in the water are then translated into "virtual partial pressures" using appropriate solubility constants based on Henry's law. The need to define a virtual partial pressure for the acid gases arises from the fact that standards and corrosion models are based on partial pressures, while corrosion reactions are in fact controlled by the concentrations of the corrosion agents in solution. The methodology to circumvent this dilemma will be demonstrated using an example from an actual off-shore well, and a commercially available PVT/corrosion model.
The modeled H2S and CO2 partial pressures in conjunction with the calculated reservoir pH were used to evaluate the viability of martensitic stainless steels. Two scenarios were studied: a) prior to water flooding, the predicted carbon steel corrosion rate is > 100 mpy at a water cut > 30 %; whereas for regular 13Cr it is ~ 1 mpy. (Below 30 % water cut, the literature indicates a maximum carbon steel corrosion rate of 25 mpy.) When production is under waterflood the modeled corrosion rate for regular 13Cr was 5 mpy; comparable experimental data are between 5 to 10 mpy. However, the H2S partial pressure is estimated of the order of 0.5 psi, or in the domain of sour service. Additionally, the high chloride levels encountered (120,000 ppm) made 13% Cr steel questionable for this application. The case history also highlighted the importance for the need of high quality analytical data.
Key words: Modeling, acid gases, corrosion rate, bubble point pressure, materials selection, equation-of-state.
INTRODUCTION
Materials selection involves an assessment of the production/reservoir chemistry, corrosion rate evaluation of candidate tubular materials, and determining the cracking resistance of corrosion resistant alloys (CRAs). Standards used for material qualification purposes (e.g. NACE MR0175/ISO 15156) specify acid gas concentrations in terms of partial pressures. For production reservoirs, where the total pressure is above the bubble point pressure of the oil, and the fluids are in single phase downhole, the acid gas partial pressures cannot be directly assessed from the total pressure and the mol fractions of the dissolved gases.
In order to deal with this difficulty a procedure was devised, based on a thermodynamic model, to determine the partitioning equilibria of CO2 and H2S between the hydrocarbon and water phases and thereby obtaining the concentrations of the acid gases in either phase.
Using solubility equilibria correlations, the acid gas partial pressures are then determined from their respective concentrations in the aqueous phase.
In most instances the CO2 concentration in the oil is given in the complete hydrocarbon analyses as obtainded by various gaschromatographic methods. H2S may or may not be included in the GC methods. If the GC methods are are not sufficiently sensitive or are not calibrated for low levels of H2S, its concentration in the brine is extracted from other information.
Once the concentrations of the acid gases in the aqueous phase are obtained, partial pressures are calculated as indicated above by means of solubility constants as defined by Henry's law.
This procedure is schematically illustrated in Figure 1.
Figure 1: Schematic Illustration of the Partitioning Equilibrium of CO2
between the Oil and Brine Phases
The model assumes that in the reservoir an oil phase is in contact with an aqueous brine phase. The total pressure is high enough such that there is no gas phase. From the oil analysis the CO2 concentration in the oil is known. Neither the solubility constant of CO2 in the oil nor the partial pressure of CO2 are known. Nevertheless, thermodynamically one can define a virtual partial pressure of CO2 which is the same over oil as over the brine phase. When the oil phase is in contact with the brine, a CO2 partitioning equilibrium estabilishes itself. One can then calculate the CO2 concentration in the oil. If the solubility constant of CO2 in the brine is known the virtual
To illustrate the methodology, an off-shore oil reservoir, whose downhole pressure is above the bubble point pressure, is presented as a case study. The three objectives of this project were: (1) to estimate the acid gas partial pressures; (2) assess the corrosivity of the well fluids in the event of a waterflood; and (3) to determine the corrosion behavior of both carbon steel and martensitic stainless steels (MSS) in the subject well.
To accomplish these objectives a commercial thermodynamic/corrosion software package was used, in conjunction with a review of relevant literature sources. The results of the combined reservoir and corrosion analyses were then applied to determine an appropriate production tubular material based on cracking resistance.
EQUATION OF STATE AND CORROSION SOFTWARE
For partitioning calculations the thermodynamic software model developed by Anderko and associates was used [1]. The theoretical framework includes an extended Pitzer-Debye-Huckel equations that model electrolyte systems (e.g. activity coefficients) [2], and uses the enhanced Soave-Redlich-Kwong (SRK) equation of state (EOS) model for thermodynamic calculations involving liquid-vapor equilibria (e.g. fugacity coefficients). The parameter coefficients used for the SRK calculations are imbedded within the framework and are based on American Petroleum Institute (API) specifications.
The software package also includes material-specific algorithms that calculate steady-state corrosion rates for both "generic" carbon steel and regular 13Cr [1, 3, 4]. Numerous publications by the developers [5-8] (and others [9]) demonstrate the predictiveness of the model, and a number of comparisons were carried out to verify some of the predictions based on Blade's own work or to specific literature data.
GENERAL CONSIDERATIONS IN SELECTION OF MATERIALS FOR OIL FIELD TUBULARS
The materials used in the completion of a gas or oil wells, in particular the production tubing, liner, and casing, need to perform over the life of the well in accordance with a series of criteria, the limits of which are usually set by economic constraints.
The first criterion consists of acceptable general weightloss corrosion rates. For a typical well life of 20 years, an acceptable calculated corrosion rate limit may be 5 mpy (0.125 mm/yr) [10]. However, depending upon the reservoir temperature and the CO2 to H2S partial pressure ratio, corrosion rates for carbon steel in excess of 100 mpy may be expected [11, 12]. In such situations, mitigation may include the application of corrosion inhibitors or the use of corrosion resistant alloys (CRA) [13]. To assess the corrosion severity of a reservoir, models are used to evaluate the corrosion behavior of carbon steel versus CRA under HPHT conditions.
A second criterion for the selection of the tubing material is its resistance to sulfide stress cracking (SSC) and stress corrosion cracking (SCC) [13]. SSC resistance is evaluated by standardized test methods, as described in NACE Standard MR0175/ISO 15156. In order to define the appropriate SSC test conditions, the prevailing pH and the H2S partial pressure, as well as the chloride concentration in the water phase, must be defined. The relationship between pH and the H2S partial pressure is illustrated diagrammatically in NACE MR0175/ISO 15156. In order to make use of these diagrams when the reservoir pressure is above the bubble point pressure a virtual partial pressure must be calculated.
The third criterion is that the tubing material has to perform over a wide range of temperature/pressure conditions and produced fluid compositions as these parameters may change over the lifetime of the well.
RESERVOIR DATA
Produced Water Analysis
The extent of corrosion on candidate tubulars is dependent on the produced water composition. Table 1 lists the key components in the produced water analysis relevant to the present case history The high chloride content (> 120,000 mg/L) may be unusual butreasonable as the production from this off-shore well was from below a salt dome.
In order to model the in situ reservoir pH properly, the alkalinity must be evaluated. Generally, laboratories use a titration method to measure the alkalinity of a particular water sample. As the water analysis listed a pH of 7.24, the volatile organic acids (VOAs) (e.g. acetate [HCOO–]) are most likely salts and contribute to the formation water's alkalinity. As an approximation, by subtracting the total VOA moiety (653 ppm) from the apparent alkalinity (669 ppm), the bicarbonate concentration is actually 16 ppm.
Brent: Let's try and focus on why the different parameters. "Corrosion rate is controlled by the pH. The pH is dependent on alkalinity and acid gas partial pressure. The alkalinity is composed of both the bicarbonate and the volatile organic acids. The model uses both the bicarbonate and VOA to determine alkalinity and compare with the measured pH (reconciliation)
Just to repeat: bicarbonate is used for scaling assessment, alkalinity is used for corrosion estimation.
Assessment of the Downhole Environment
In order to evaluate the corrosion, and especially cracking resistance, of potential candidate tubular materials, the H2S partial pressure is required, along with the pH and salinity of the produced water. The highest CO2 concentration reported was 3.75 % of the total produced fluid stream. The reported H2S concentration ranged between 5 to 20 ppm in oil phase, and 5 ppm is expected in the water phase, following initiation of a possible water flood.
Based on this information two alternative scenarios were emerged: (a) The water phase contains between 0 and 5 ppm H2S; or (b) the oil phase contains 0 to 20 ppm H2S in the oil. The corresponding H2S partial pressure was calculated for each scenario. Subsequently, a corrosion rate sensitivity study was performed by varying the H2S concentration.
Ultimately, the results were applied to assess the cracking resistance under hot bottomhole and cold shut-in conditions. For brevity, however, the article will focus on the development of a method to model the H2S and CO2 partial pressures in fluids above the bubble point pressure, and applying the results to calculating corrosion rates.
Determining the H2S Partial Pressure
As indicated by Hausler [14] and Skogsberg [15], it is incorrect to assume that the H2S concentration in the water or hydrocarbon phase equals the mole fraction in the "gas" phase. Therefore, a strategy was developed to derive realistic PH2S and PCO2 values for the oil-dominant production well whose downhole pressure is above the bubble point.
Under ideal conditions, the solubility (or equilibrium concentration) of a gas in an aqueous solution is directly proportional to the partial pressure of that gas. This relationship is known as Henry's law [16, 17]:
cCO2= kCO2 H2O pCO2 cH2S= kH2SH2O pH2S
where, H(T) is the Henry's constant (mol/L.at). The strict Henry's law definition assumes ideal gas conditions prevail. This renders Eq (1) only applicable to dilute systems at relatively low pressures. As pressure and salinity increase, non-ideal behaviors of both gas and water phases begin to affect the solubility. Three corrections [18, 19] are required to account for these non-ideal behaviors of gas and water phases: The fugacity (Φ) coefficient accounts for non-ideal gas behaviour; the activity (γ) coefficient for non-ideality of dissolved gas in liquid; and an exponential term, known as the Poynting's correction (νi ) [16], considers the effect of high pressures on the partial molar volume of the solute under infinite dilution. The modified Henry's law, i.e. Ensemble Henry's law, for non-ideal systems has the following expression:
(2)
Eq (2) accurately describes gas-liquid equilibrium for non-ideal systems at high pressures containing H2S [16, 18, 19]. Using the Ensemble Henry's law, the partitioning of CO2 and H2S between the liquid oil and liquid water phases can be determined.
Based on the above discussion, the following methodology was applied to partitioning and corrosion rate calculations. For this project, both the water composition (Table 1) and the oil composition (Table 2) were used:
Step 1
To investigate the partitioning of acid gases between the oil and brine phases, the reported gas composition was mixed with the water sample to generate a specified volume ratio of 1:9 for both bottomhole and wellhead temperatures. The resulting "combined fluid composition" is reported in Table 3.
For partitioning calculations, the H2S content in the total fluid stream was adjusted until there was ~ 5 ppm in the water and the corresponding amount in the oil phase was determined (Table 4); subsequently, the H2S partial pressure corresponding to 5 ppm H2S in the water phase was extracted.
Alternatively, the H2S concentration was fixed to 20 ppm in the oil, allowing the H2S concentration in the water to vary (Table 4). The [H2S] in the water was then used to determine the corresponding partial pressure.
Step 2
To determine the partial pressure, the pressure is reduced slightly below the bubble point pressure for the water/oil/H2S system, at the reservoir (155 °F) and wellhead (40 °F) temperatures, such that a small gas phase forms.
The acid gas partial pressure was then plotted against its concentration in the water phase. A quadratic "line-of-best-fit" with an R2 value > 0.995 or higher was selected in order to calculate a virtual partial pressure above the bubble point pressure (see Figures 2 and 3 for CO2 and H2S, respectively).
This procedure establishes two H2S concentrations in the water and two corresponding partial pressures. This approach brackets the H2S partial pressure used to assess the cracking behavior of specific metallurgy.
Please note: If the curves were drawn in liner coordinates you would get a straight line as predicted – the slope would correspond to the solubility constant. What I don't understand is why the H2S show a different behavior.
Step 3
The bracketed H2S partial pressures can now be applied to fit-for-purpose assessment.
Corrosion rates were also determined as a function of temperature for carbon steel and regular 13Cr under downhole conditions (155 °F and 12,500 psi) using the total fluid composition (Table 3).
Results and Discussion
Partitioning Calculations
Using the above thermodynamic strategy and reservoir assumptions, the model was used to quantify an equivalent partial pressure for acid gases in oil wells. As shown in Figures 2 and 3, a quadratic relationship was selected to calculate the virtual partial pressure for both CO2 and H2S, respectively. As expected, at a constant acid gas concentration, the corresponding partial pressure decreases as the temperature decreases. The consequences of this phenomenon (with regards to revisiting standard SSC testing procedures) have been addressed in a previous paper [ref].
As shown in Tables 4 and 5, H2S is ~ 2 and 4 times more soluble in oil than in water under downhole and shut-in well conditions, respectively. When 21 ppm H2S exists in the oil phase, the equivalent partial pressure is 0.379 psi at 155 °F and 0.111 psi at 40 °F; this value is above the NACE limit for sour service (i.e., PH2S 0.05 psi). Assuming an aqueous [H2S] of 5 ppm, a PH2S of 0.113 psi under downhole conditions and 0.029 psi under wellhead shut-in conditions is obtained. Why is the curvature in Fig 3 different from the one in Fig. 2
Based on the analysis, both ranges were considered in order to evaluate alternate alloys to carbon steel and regular 13Cr stainless steel as design options to mitigate corrosion and SSC should this field sour in the event of a waterflood.
Corrosion Assessment
The following discussion is based on a projected flood scenario whereby H2S might be generated. Based on the results of Table 4, Figure 4 shows the predicted corrosion rates for regular carbon steel and 13Cr. In the presence of 5 ppm H2S, the predicted corrosion rates for:
Carbon steel are reduced from ~ 400 mpy (H2S free) to ~ 45 mpy; still too high for tubular application.
13Cr increase from < 1 mpy (H2S free) to ~ 5 mpy. Thus, the corrosion threat is manageable.
At low concentrations (< 0.5 psi), H2S is known to inhibit the CO2 corrosion mechanism on carbon steel [3, 12] within the temperature range of interest.
Implications of Corrosion Rate Assessment
Carbon steel corrosion rates, in the absence of H2S, are on the order of 300 to 400 mpy. These corrosion rates are consistent with the experimental results [20, 21]. Ikeda, et al. [20] obtained corrosion rates of ~ 120 to 200 mpy at 150 and 212 °F based on a 96 hour corrosion test in a deaerated autoclave on pure iron in 5 % NaCl with 14.6 psi CO2 at 77 °C (171 °F). Hausler and Stegmann [21] obtained an uninhibited carbon steel (N-80) corrosion rate of ~ 400 mpy based on weightloss and hydrogen measurements from rotating coupon autoclave testing, following 90 hours of exposure at 125 °F, 1000 psi CO2, 100,000 ppm Cl– brine. The difference in corrosion rates between prediction (this study) and experiment is related to temperature, alkalinity, type of steel, CO2 concentration, and exposure time (which is related to corrosion kinetics). The presence of 5 ppm H2S (0.113 psi) drops the corrosion rate to ~ 45 mpy. A decrease in the CO2 corrosion rate in the presence of a low [H2S] is consistent with the literature [22]. Nevertheless, uninhibited carbon steel is not recommended given for the subject well.
In the absence of H2S, the corrosion rates for regular 13Cr are < 1 mpy, however rates increase to ~ 5 mpy in the presence of 5 ppm H2S in the water. Actual experimental data performed by Blade under 12,000 ppm Cl– conditions (Table 6) reports a corrosion rate for regular 13Cr ~ 3 mpy, while the corrosion rate for super 13Cr (i.e., MSS with increased concentrations of Ni and Mo) is at least 5 times lower. Table 7 reports literature experimental data performed at high
[Cl–] and under the absence/presence of H2S and bicarbonate for regular 13Cr [10, 23]. As expected, the corrosion rates increase with temperature and a higher PCO2, which corresponds to a decrease in pH (~ 3.5). The combination of low PH2S, moderately high [Cl–], and the presence of bicarbonate, which increases the pH to > 4, decreases the corrosion rate by an order of magnitude and is consistent with the model predictions for regular 13Cr.
In addition to general corrosion concerns, production tubing material must be resistant to cracking. Having determined the reservoir pH, acid gas partial pressures, and assessed the corrosion threat, the results were then applied to aid in a cracking assessment. The H2S partial pressure and corresponding pH for bottomhole and wellhead shut-in conditions are plotted in Figure 5, with respect to NACE Standard MR0175. For brevity, an in depth discussion on cracking is beyond the scope of this article. Nevertheless, since the pH is expected to be > 4 and the PH2S is low (< 0.11 psi at 40 °F), the probability of SSC is low. However, the high chloride levels encountered (120,000 ppm) made regular 13Cr steel questionable for this application.
SUMMARY AND CONCLUSIONS
ACKNOWLEDGEMENTS
Financial support for the article's publication was provided by Blade Energy Partners. A.J. Gerbino is gratefully acknowledged by the authors for his guidance.
REFERENCES
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[2] A. Anderko, P. Wang, M. Rafal, Electrolyte solutions: from thermodynamic and transport property models to the stimulation of industrial processes, Fluid Phase Equilibria, 194-197 (2002) 123-142.
[3] A. Anderko, Simulation of FeCO3 / FeS Scale Formation Using Thermodynamic and Electrochemical Models in: NACE, 00102, 2000.
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[12] S.N. Smith, J.L. Pacheco, Prediction of Corrosion in Slightly Sour Environments, in: NACE, 02241, 2002.
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[14] R.H. Hausler, Methodology for charging autoclaves at high pressures and temperatures with acid gases, Corrosion, 54 (1998) 641-650.
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[16] C. Plennevaux, N. Ferrando, J. Kittel, M. Frégonèse, B. Normand, T. Cassagne, F. Ropital, M. Bonis, pH prediction in concentrated aqueous solutions under high pressure of acid gases and high temperature, Corrosion Science, 73 (2013) 143-149.
[17] M. Gao, R. McNealy, J. Larios, R.M. Krishnamurthy, Critical Review: FAD Assessment Methods for Crack-Like Flaws in Pipelines, in, NACE Internation, Houston, TX, 2005.
[18] J.J. Carroll, What is Henry's Law?, Chemical Engineering Progress, 87 (1991) 48-52.
[19] J.J. Carroll, A.E. Mather, The solubility of hydrogen sulphide in water from 0 to 90°C and pressures to 1 MPa, Geochim. Cosmochim. Acta, 53 (1989) 1163-1170.
[20] A. Ikeda, S. Mukai, M. Ueda, Prevention of CO2 Corrosion of Line Pipe and Oil Country Tubular Goods, in: CORROSION/84, NACE International: Houston, TX, 1984, pp. 84289.
[21] R.H. Hausler, D.W. Stegmann, Laboratory Studies on Flow Induced Localized Corrosion in CO2/H2S Environments IV: Assessment of the Kinetics of Corrosion Inhibition by Hydrogen Evolution Measurements, in: CORROSION/91, NACE Internation, Houston, TX, 1991.
[22] M.B. Kermani, A. Morshed, Carbon Dioxide Corrosion in Oil and Gas Production - A Compendium, Corrosion, 59 (2003) 659-683.
[23] G. Fierro, G.M. Ingo, F. Mancia, XPS Investigation on the Corrosion Behaviour of 13Cr Martensitic Stainless Steel in CO2-H2S-Cl– Environments, in: NACE, 88215, 1988.
Type equation here.
