In the context of the ever harsher production conditions encountered in the oil and gas industry, there is a need for improved materials qualification methods for sour (H2S) environments. The classic approach, based on H2S partial pressure, does not adequately characterize the corrosive severity of, in particular, high-pressure environments such as high-pressure high-temperature wells. This paper describes the introduction of non-ideal thermodynamics in the characterization of environmental severity. The focus is on sour exposure and using H2S fugacity or H2S aqueous concentration rather than H2S partial pressure. Experimental work has shown that these approaches are valid, at least for sulfide stress corrosion cracking of steel, and some of the benefits are demonstrated. It is recommended to extend this work to other materials and degradation mechanisms and also to upgrade laboratory test methods and industry standards for this purpose.

The oil and gas industry is moving into ever harsher production conditions. Deeper water, deeper wells, higher pressure, and exposure to hydrogen sulfide all come into play. Huizinga, et al.,1  provides an example of this trend. Classic methods to assess the corrosive severity of such environments often are conservative, but in some cases turn out not to be conservative, as will be argued in this paper (see Assessing the Effect of Pressure section). To be able to safely and reliably operate under these conditions, the industry needs to dig deeper in understanding and describing this exposure. This concerns both the actual field conditions and laboratory testing that purports to represent these field conditions.

The present paper describes the state of the art when it comes to dealing with these aspects in the context of corrosion and cracking in sour (hydrogen sulfide, H2S) service. Alternatives to the classic H2S partial pressure approach will be discussed, including the role of non-ideal thermodynamics, in particular at high pressure. These effects play out both in the gas phase and in the liquid phase. Most research so far has been done on carbon and low alloy steels but the behavior of corrosion resistant alloys is equally important.

While it is relatively common to describe the chemical potential of H2S in a gas phase by using the concept of fugacity, detailed consideration also needs to be given to the effect that high pressure exerts on H2S in a liquid phase. Taking account, the former usually leads to a less conservative assessment and thereby enables a more realistic corrosion and cracking resistance evaluation of materials. The latter effect, however, in particular for liquid-full (gas-free) systems, such as deep oil wells, implies that the classic approach of using bubble point H2S partial pressure may not be conservative.

Next to the mentioned field exposure considerations, attention will be given to the definition of laboratory test environments that properly represent such conditions. While in the first instance this is important when researching non-ideal thermodynamic effects, it is also essential for materials qualification that adequately ensures safe field performance for current and future harsh oil and gas production conditions. For the industry as a whole, standardization of models and methods used is indispensable and is currently receiving increasing attention.

In this paper, the term fugacity as used in the title aims to signify the introduction of non-ideal thermodynamics in materials assessment. It will become clear, however, that such thermodynamics are more complex than suggested by a single term.

In oil and gas production, field conditions to which construction materials may be exposed can vary widely between fields and applications. A typical and extreme example are today’s high-pressure high-temperature (HPHT) wells.1  Pressures of 1,000 bar (100,000 kPa) and temperatures of 200°C are not uncommon, in particular for wells that run as deep as 6 km.

Carbon and Low Alloy Steels

For deep HPHT wells, design requires high-strength steels to be used for tubular materials, as otherwise the weight of the string could become prohibitive as a result of the wall thickness required. Hence steels with specified minimum yield strength (SMYS) of 930 MPa to 1,000 MPa (125 ksi to 145 ksi) are selected by the well engineer for such applications. At the same time, it is known that at higher temperatures the likelihood of encountering H2S in the formation increases.2  However, the resulting combination of high-strength low alloy steel (LAS) or carbon steel (CS) and H2S is undesirable from the perspective of avoiding sulfide stress corrosion (SSC).3  Classic design rules based on H2S partial pressure may prohibit designing and operating wells under such extreme conditions, even at low H2S levels.3  A detailed assessment of the H2S level encountered in service and a thorough evaluation of the SSC resistance of the high-strength steels that are to be used for well tubing and casing is essential, taking account of the effect of high pressure on H2S chemical potential.

Super Martensitic Stainless Steels

Another example concerns the use of super 13Cr martensitic stainless steels (SMSS) for well tubing. The corrosion cracking resistance of SMSS in produced formation brines decreases markedly when H2S is present.4  This is the case for both the low-temperature SSC and the elevated temperature chloride stress corrosion cracking (SCC) mechanisms. To facilitate use of the material for high-pressure well completions, knowledge of the environmental limits concerning SSC and SCC is essential. Again, taking account of the effect of pressure on H2S beyond the classic partial pressure approach3  may facilitate demonstration of corrosion and cracking resistance under field conditions and thus allow proper use of SMSS.

Corrosion Resistant Alloys

What applies to LAS, CS, and SMSS with regard to H2S chemical potential is also true for corrosion resistant alloys (CRA). Environmental limits to prevent SCC of CRA in sour service are generally given in terms of H2S level, chloride concentration, acidity, and temperature.3  Current limits for H2S are based on its partial pressure and therefore in many cases are conservative, forcing the selection of higher alloyed versions of CRA. Under the condition that proper test methods are used for their qualification, CRA materials selection may be optimized by taking account of the pressure effect on the H2S chemical potential.

In all three above examples, moving beyond classic ideal thermodynamics and considering non-ideal behavior facilitate the optimal selection and qualification of materials for sour service. In many less extreme cases, such considerations may not be required for selection and qualification, but at increased pressures as in, e.g., HPHT wells unnecessary conservatism may be removed and in some cases undue optimism can be avoided, as will be discussed in more detail below.

Mechanisms

The mechanisms of corrosion and cracking in sour environments are complex by nature. The chemistry of H2S and iron (Fe), the uptake and effect of hydrogen (H) in steel, the localized nature of the attack, and material toughness and stress all come into play. It is not the intent of this paper to describe these mechanisms in detail but rather to focus on the role of H2S. The terminology used here is aligned with the global NACE MR0175/ISO 15156 standard.3 

The corrosion of steel comprises the anodic and cathodic reactions, respectively:

formula
formula

The adsorbed hydrogen (Hads) may either re-combine to form H2 and be released from the surface without causing harm:

formula

or it may diffuse into the steel, where it can cause embrittlement. The latter path is promoted over H2 formation by the presence of H2S. Hence, H2S causes an enhanced likelihood of steel embrittlement, which may result in SSC. Because this mechanism is linked to the cathodic reaction, it is generally referred to as cathodically controlled corrosion cracking.

On CRAs, the passive nature of the alloy dominates behavior. H2S contributes to destabilization of the passive surface layer and increases the likelihood of localized corrosion. Where the alloy is attacked, a stress riser is formed and cracking may initiate anew, creating a surface that lacks passive protection, so that the mechanism can propagate as SCC. Straining the material, in particular into the plastic regime, can also cause local damage to the passive layer, which then starts SCC. In the SCC mechanism, the role of H2S is to locally facilitate metal dissolution, i.e., the anodic reaction, and is therefore generally referred to as anodically controlled corrosion cracking.

Severity—The “Northwest-Southeast” Principle

The classical approach to quantifying the impact of H2S at pressure on SSC describes its effect by considering the H2S partial pressure (pH2S) combined with pH. The NACE MR0175 standard,3  based on a large body of experimental data, adopts this as the “Northwest-Southeast” (NW-SE) principle, as depicted in Figure 1 (reproduced from NACE MR01753 ). In region 0, no SSC is expected. SSC likelihood increases when going from regions 1 to 3, following the blue NW-SE arrow. The asterisk indicates the common “environment A” test condition, defined in NACE TM0177.5  Testing at these severe conditions covers the severity of all regions in the diagram. Unfortunately, for the mentioned high-strength CS and LAS for HPHT service, it is nearly impossible to pass SSC tests this way and focused qualification testing in the other regions, under simulated service conditions, needs to be applied. By following the NW-SE principle, a few tests may cover a large set of pH-pH2S conditions. Keeping this principle in mind, an improved assessment of materials suitability for sour service may focus on the introduction of the non-ideal thermodynamic effect on H2S.

FIGURE 1.

Regions of severity for SSC as defined in NACE MR0175.3  No SSC is expected for CS and LAS in region 0; SSC likelihood increases when going from region 1 to 3, following the NW-SE arrow. The asterisk indicates the common “environment A”5  test condition.

FIGURE 1.

Regions of severity for SSC as defined in NACE MR0175.3  No SSC is expected for CS and LAS in region 0; SSC likelihood increases when going from region 1 to 3, following the NW-SE arrow. The asterisk indicates the common “environment A”5  test condition.

For CRAs, next to pH2S and pH, chloride content and temperature also come into play, rendering the materials assessments more complex. NACE MR01753  outlines the basic principles. Similar to the effect of H2S at pressure on CS and LAS, focusing on the introduction of the non-ideal thermodynamic effect on H2S may serve as a useful approach.

Neither for the cathodic nor for the anodic corrosion cracking mechanisms may it be taken for granted that the non-ideal thermodynamic effects are fully covered by considering their effect on H2S only. Although useful as a first approach, proper, extensive test programs are needed to demonstrate validity and prove fitness for service of selected materials. Definition of programs requires not only the assessment of non-ideality in the service environment foreseen in the field, but also that of the test environment used to represent field service.

Emphasis in this paper is on high pressure, but the degree of non-ideality in a corrosive environment depends on the combination of several parameters, including pressure, temperature, and composition. Hence, each of these parameters needs to be reflected in the definition of environmental severity.

Descriptive Parameters—Including Non-Ideality

NACE MR01753  requires that the corrosiveness of any test environment shall be at least as severe as the service exposure it represents. Therefore, proper characterization of the environmental severity for corrosion and cracking is essential. With respect to sour SSC and SCC, it was argued earlier that the non-ideal thermodynamic effect of pressure on H2S may be taken as a useful approach. Possible parameters that may be chosen are the following (see also Grimes, et al.6 ):

  • pH2S partial pressure:

    The partial pressure of a gas species, e.g., CO2 or H2S, is defined as that part of the total pressure that can be ascribed the specific species, using a simple summation of partial pressures for each of the gas species present in the gas phase to arrive at the total pressure (P). The concept is based on the ideal gas law that describes this additive, linear behavior, but it starts to deviate from reality when non-ideal thermodynamic effects come into play. At rising pressure, when interaction between gas molecules increases, partial pressure no longer accurately describes the species behavior. As described above, pH2S is commonly used and, in fact, strongly emphasized in current standards. From a historic perspective, this is understandable but in the current context of, e.g., HPHT applications, such standards need revision and close consideration of them still being conservative.

  • xH2S-aq aqueous concentration:

    Corrosion and cracking being phenomena that occur in the aqueous phase, it is logical to use the aqueous concentration of H2S in a definition of severity. xH2S-aq is often expressed as a mole fraction. The popularity of using pH2S rather than xH2S-aq is largely a result of the historical development where issues with cracking in sour environments occurred first in gas production systems and also a result of the fact that gas composition measurements are much more readily available than those of aqueous concentrations. NACE MR01753  accepts use of pH2S, as well as xH2S-aq, to describe environmental severity.

    It is to be noted that concentrations of species can also be defined in other phases than water such as a liquid hydrocarbon phase or a super critical (“gas-liquid”) phase. As corrosion takes place in the aqueous phase, xH2S-aq is discussed here, but when concentrations such as xH2S-aq have to be calculated for a multiphase oil-water-gas system, all phases figure in the calculation, which is then based on thermodynamic equilibrium, i.e., assumes the same chemical potential of the H2S species for each phase (see below under fH2S and μH2S).

  • fH2S fugacity:

    With increasing pressure, it is known that the gas phase chemical potential is no longer well represented by partial pressure. The thermodynamic concept of fugacity, which includes non-ideal behavior in the gas phase, remedies this situation. The fugacity of a gas species, e.g., CO2 or H2S, represents the effective pressure of a real gas species and has the same chemical potential (Gibbs free energy) as the real gas species. As such, it can be considered an “effective partial pressure,” incorporating the non-ideal thermodynamic effects in the real gas that are ignored in the partial pressure derived from the ideal gas law. It is dependent on and generally calculated from the total pressure, the mole fraction of the species in the mixture, and its fugacity coefficient, which in turn depends on temperature. The concept of fugacity is applicable to all phases, gas or liquid, and can be thought of as “escaping tendency”—the driver for a component to leave a phase. At equilibrium, the fugacity for each component is the same in all phases of a mixture, gas or liquid. In this paper, the term fugacity is primarily dealt with as a property of species in the gas phase, expressed in units of pressure, but because at equilibrium its value is the same in each of the phases, it is equally applicable to the aqueous phase or a hydrocarbon phase.

  • aH2S activity:

    Activity, also called chemical activity, may be considered a “pseudo mole fraction.” The chemical activity of a gas species, e.g., CO2 or H2S, is defined as the (unit-less) ratio of its actual fugacity divided by its fugacity at a conveniently defined reference state. Sometimes a low-pressure reference state is chosen, and sometimes a high-pressure (P) one. Activity is therefore meaningless if the reference state is not specified. Activity also incorporates the effect of brine salinity on a species. Activity is often expressed as the mole fraction xH2S of the species in the liquid phase multiplied by an activity coefficient γH2S, the latter reflecting salinity effects. In that case, a reference state at pressure P has de facto been chosen and the high-pressure effect on activity, the Poynting correction (see Relations Between Parameters section), is not evident. As activity and fugacity are unambiguously related and are derived from the thermodynamic concept of chemical potential (partial Gibbs free energy), it is sufficient to specify either activity or fugacity. In this paper, the term activity is primarily used as a property of species in the liquid or aqueous phase.

  • μH2S chemical potential:

    The chemical potential, or partial molar free energy, is the more fundamental thermodynamic property from which activity and fugacity are derived. At constant temperature and pressure, it is the partial molar Gibbs free energy. At equilibrium, i.e., when the Gibbs free energy is at its minimum, the chemical potential of a species is the same in each phase. An explanation of the relation between chemical potential, fugacity, and activity can be found, for instance, in Ramshaw.7 

For the purpose of characterizing the severity of an H2S containing phase, it is not necessary to consider each of the above parameters in detail. As both fugacity and activity are directly and unambiguously derived from the chemical potential and fugacity can be defined in each phase, it is sufficient to consider pH2S, xH2S-aq, and fH2S. Instead of using fH2S, one could use aH2S, which is not uncommon for a liquid phase, but it does require specification of the reference state used. In this paper focus is on pH2S, xH2S-aq, and fH2S.

Relations Between Parameters

The effect of pressure, temperature, and composition on the deviation from ideal thermodynamic behavior can be captured in these three parameters. The relations between them (and for completeness aH2S) are as follows:

formula
formula
formula

where yH2S is the mole fraction of H2S in the gas phase, ϕH2S is the fugacity coefficient, describing non-ideal behavior in the gas phase (usually calculated from an equation of state model and depending on pressure, temperature, and composition), and P is the total pressure.

The aqueous concentration xH2S-aq can be derived making use of Henry’s law, where HH2S is Henry’s law constant which depends on temperature. Depending on the degree to which non-ideality is to be included, Henry’s law takes different forms:

  • Assuming ideal gas behavior:
    formula
  • With gas non-ideality, includes gas fugacity coefficient:
    formula
  • Ensemble law with gas and liquid non-ideality, includes gas fugacity coefficient as well as aqueous activity coefficient and Poynting correction:
    formula
    where γH2S is the activity coefficient in water and the exponential term, the Poynting correction, describes the effect of pressure on the chemical potential of H2S in the aqueous phase. The latter correction is related to the small but non-negligible liquid compressibility.

For further details, Chambers, et al.,8  and references contained therein may be consulted.

PH2S, fH2S, xH2S-aq, and Conservatism

In general terms, when using either of the above parameters, a varying degree of conservatism is introduced in the severity assessment. The differences are most pronounced at high pressure, as in, e.g., HPHT applications, when the ideal gas law is an increasingly poor approximation of real phase behavior. This is explored below. A detailed account is provided in Grimes, et al.9 

The partial pressure concept, based on the ideal gas law, provides an accurate representation of thermodynamic behavior of gas species like CO2 and H2S at near-atmospheric total pressures. It is well established that, at increasing gas pressure, the chemical potential of H2S drops significantly. The H2S fugacity (expressed in units of pressure) may reduce to only a fraction of the H2S partial pressure. Figure 29  quantitatively illustrates these effects as calculated for a typical case of a methane/H2S gas mixture with a fixed amount of H2S equivalent to pH2S = 0.3 kPa (horizontal dotted line). The drawn line for the fH2S ratio is in fact the fugacity coefficient ϕH2S. Also shown is the trend for H2S dissolution in an aqueous phase in equilibrium with the gas phase. The triangled line for xH2S reflects the ratio between the H2S concentration in the aqueous phase at actual pressure P to that at 1 bar (100 kPa). If the Poynting correction would not have been included, this line would display the same curve as that for fH2S.

FIGURE 2.

The effect of total pressure P in a gas mixture of methane and H2S with a fixed amount of H2S, equivalent to pH2S = 0.3 kPa (3 mbar), expressed as the ratio between parameters pH2S, fH2S, and xH2S-aq and their respective values at P = 100 kPa (1 bar).9 

FIGURE 2.

The effect of total pressure P in a gas mixture of methane and H2S with a fixed amount of H2S, equivalent to pH2S = 0.3 kPa (3 mbar), expressed as the ratio between parameters pH2S, fH2S, and xH2S-aq and their respective values at P = 100 kPa (1 bar).9 

As a consequence, the differences between using these parameters to characterize an environment are significant. If, following the classic approach, the field condition is characterized by pH2S and this number is reproduced in a lab test, a degree of conservatism is built in when compared with a fugacity based approach. The latter would reproduce the field fH2S in a lab test, following the dropping curve in Figure 2, i.e., well below the horizontal dotted line for pH2S. Simulating pH2S is therefore usually considered the safe choice for systems with a gas phase but may introduce unnecessary conservatism and, hence, lead to disqualification of materials where they may be needed most. Only at very high pressures (typically in excess of several thousands of bars) could ϕH2S become larger than 1. In that case, using pH2S would no longer be conservative over fH2S.

Instead of characterizing severity by pH2S or fH2S, concentration xH2S-aq may be chosen to be reproduced in a test environment.10  NACE MR01753  in principle considers this an acceptable approach and it obviously is linked to the fact that corrosion takes place in the aqueous phase. The consequence of this choice becomes evident from Figure 2. At near-atmospheric pressure, the same result as for pH2S and fH2S is obtained. At increasing pressure, the xH2S curve follows that for fugacity, at least as long as the Poynting correction does not come not play. At high pressure, the xH2S line drops significantly below that for fH2S, indicating that the concentration approach becomes less conservative than the fugacity approach. In fact, using xH2S to characterize the severity of the environment ignores the non-ideal thermodynamic effect that high pressure may have on species in a liquid phase. At which pressure this effect becomes significant depends on temperature and composition of the environment mixture.

The data presented in Figure 2 were calculated for a specific gas mixture of methane and H2S at ambient temperature in equilibrium with a water phase. The results demonstrate typical ranges of fH2S and xH2S-aq and the deviation from ideal behavior is seen in a pressure range from 1 bar to 1,400 bar (100 kPa to 140,000 kPa). For higher temperatures, the deviation from ideality becomes smaller. Also, for other mixtures of species, the curves change. Finally, this example is for a gas system. For a system containing hydrocarbon liquid, even though trends are similar, different results will be obtained. In particular mixtures at pressures above their bubble point, which are often encountered in high-pressure oil wells, may behave differently.

PH2S, fH2S, or xH2S-aq—Which is Realistic?

The historic approach as reflected in NACE MR01753  is based on the pH2S approach. The standard has been successfully applied for many years and a large body of lab and field data supports the approach. However, as argued in the introduction, today’s environments in oil and gas production, in particular at HPHT, force an adapted approach. A less conservative assessment is needed, with evaluation conditions that closer reflect thermodynamic reality. At the same time, such an approach may reveal that in some conditions the pH2S approach may not even be conservative. With the pH2S concept closely tied in with the ideal gas law, it should be no surprise that different results are obtained when non-ideality is specifically included. In fact, pH2S itself is a “virtual” parameter that can only be calculated, not measured.

Therefore, it is safe to use pH2S in the typical realm of classical sour gas production, which lies at the basis of current standards. On fundamental grounds, it would be more appropriate to use parameters that reflect the thermodynamic reality of non-ideal behavior. Two such parameters have been discussed: fH2S and xH2S-aq. Up front, it is not evident which one should be preferred, and, as Figure 2 demonstrates, there is a large pressure regime where the two might yield similar assessment results. Considering the nature of fH2S versus xH2S-aq, the fugacity approach would be more appropriate where thermodynamic equilibrium is controlling. In case of reaction kinetic control, this may not always be true, but at least trends should be reflected correctly. Where H2S has a catalytic effect, as is largely the case in sour cracking, fH2S should work well. The need to use concentration as a more realistic parameter may arise if for instance mass transport of H2S in the aqueous phase is dominating. It should be kept in mind that the difference between the two, as explained earlier (see Relations Between Parameters section), is largely related to non-ideal behavior in the aqueous phase which only becomes significant at very high pressures.

Proof by Testing

In view of the complexity of corrosion cracking mechanisms, it is not possible to unambiguously choose between fH2S and xH2S-aq. An experimental program is needed to support the choice and several laboratory studies have in fact been reported, two recent ones being Grimes, et al.,6  and Kumar, et al.10  The former is a complex study into “The Physical Chemistry Nature of Hydrogen Sulfide Gas as it Affects Sulfide Stress Crack Propagation in Steel.” It uses the double cantilever beam (DCB) test method5  to quantify the resistance of a LAS with 95 ksi (655 MPa) SMYS against propagation of SSC at ambient temperature. Because the test result is the stress intensity factor K1ssc that can give rise to crack propagation, the K1ssc value found may be directly correlated with the pH2S, fH2S, and xH2S-aq parameters. The DCB tests were performed for a range of pH2S values from 3 mbar to 1 bar (0.3 kPa to 100 kPa), both at low (about 3 bar [300 kPa]) and high (about 350 bar [35,000 kPa]) total pressure P. For each condition, both fH2S and xH2S-aq were calculated, with obviously the largest deviation from ideality occurring at the higher P condition. Plots were then generated of the measured K1ssc values versus each of the parameters pH2S, fH2S, and xH2S-aq. The plotted results are displayed in Grimes, et al.6  From the plot of K1ssc versus pH2S, it is clear that the low-pressure K1ssc values fall on a different curve than the high-pressure values and hence, as expected, pH2S does not provide a good correlation with SSC propagation. The plot of K1ssc versus fH2S provides the best correlation, with a single curve representing both the low- and high-pressure results. Plotting K1ssc versus xH2S-aq provides a correlation that is nearly as good as that for fH2S. The conclusion may be drawn that fH2S is a proper parameter to reflect the effect of H2S on SSC propagation of a LAS, irrespective of pressure and well into the non-ideal regime. At the same time, the result does not allow discarding the validity of using xH2S-aq to characterize severity. The latter observation is in line with the results of Kumar, et al.,10  which primarily focuses on xH2S-aq.

While these results clearly confirm the inadequacy of pH2S to reflect the corrosion severity of a sour environment at elevated pressure, it should be emphasized that these results only cover a limited area within the large field of sour corrosion and cracking of CS, LAS, and CRA. Before broader conclusions can be drawn from experimental work, programs need to be extended to at least include SSC initiation next to propagation and CRA materials next to actively corrosion steels.

The now experimentally proven result that pH2S does not provide an accurate representation of severity of a sour environment when non-ideal thermodynamics comes into play has some significant consequences.

Reducing Conservatism—No Substitute for Testing

As argued earlier, for gas systems the pH2S approach still represents a conservative assessment method (unless possibly at extreme pressures of several thousands of bars because of the Poynting correction discussed). This conservatism can be reduced by using fH2S based assessments. The degree of conservatism, however, may vary widely from case to case. As an example derived from Figure 2, ϕH2S may amount to 0.6 for a 100 bar (10,000 kPa) gas pipeline, but decrease to 0.25 for a 1,000 bar (100,000 kPa) gas well. Relative to the pH2S approach, the corresponding increase in acceptable H2S level before SSC would occur for the pipeline would be a factor of 1.6 but for the gas well it would be as large as a factor of 4. Even under the assumption that fH2S is the better approach, the philosophy adopted in NACE MR01753  of materials qualification by testing in simulated service conditions cannot be abandoned. In fact, such testing not just requires the realistic determination of the severity of the field environment but also that of the test environment.

Thermodynamic Modeling Required

For the field environment, thermodynamic model analysis may be performed based on correlations of the field conditions with existing fields or based on field measurements of critical parameters. One such correlation for gas wells,2  linking H2S level to temperature, was originally defined in terms of pH2S in the formation. Recently, driven by the experimental results as reported earlier, this so-called J.T. Smith correlation was recalculated in terms of fH2S.6  As a result, the acceptable estimated formation temperature for H2S not to exceed a 3 mbar (0.3 kPa) threshold was increased from 135°C to 145°C.

The qualification of LAS for HPHT wells described in Huizinga, et al.,1  also demonstrates the careful incorporation of the fugacity concept, together with field H2S assessment and lab qualification testing. This approach facilitated the selection of a LAS that is resistant against SSC in the corrosive environment expected in the wells, which would otherwise have been impossible.

Translating the chemical analysis of fluid samples taken from a deep formation into useful parameters in itself often requires application of thermodynamic models, as does the translation of conditions measured at the surface to a downhole environment. Representing high-pressure production conditions in a qualification lab test usually involves significant simplification, as it is rare that all of the conditions can be met in the lab environment. The use of the above-mentioned “environment A” ambient pressure test condition5  to cover all regions of severity is a classic example of such simplification but clearly does not serve the purpose of reflecting non-ideal effects. Unless non-ideal effects are insignificant, it is impossible to reproduce pH2S, fH2S, and xH2S-aq all at the same time in one test environment. In the context of this paper, it is essential that the field fH2S value is accurately reproduced in the lab test environment, making use of validated thermodynamic calculation models. Also, if xH2S-aq is the parameter to be reproduced, rather than fH2S, such validated models are needed. Usually it is one single model that provides these parameter values, including aH2S and μH2S.

The availability of validated thermodynamic equation of state models for multi-phase hydrocarbon systems is far from trivial. In the oil industry, proprietary models are used by the larger organizations. Commercially available models to address the issues discussed in this paper are under development. Free publicly available models are rare and limited today. If the industry is to move ahead on the fugacity path, this situation will need to improve. One approach may be to build on the public National Institute of Standards and Technology (NIST) database11  in a joint industry effort.

The “pH2S at Bubble Point” Issue

A simplification that is often used to facilitate the assessment of material suitability and qualification testing is proposed in NACE MR01753  for “gas-free systems” such as high-pressure oil wells at pressures above their bubble point. The approach is pH2S based. The assumption is made that the severity of the environment at pressures above the bubble point can be characterized by the pH2S value at the bubble point. Based on the earlier discussion about the effect of pressure, using pH2S at P below the bubble point is a safe, conservative approach because fH2S is most likely smaller than pH2S. At P above the bubble point, however, the increase in fH2S, which is largely a result of the Poynting correction, would be ignored. Figure 3,6  calculated for a methane:decane:water mixture, displays this effect. As long as P is low enough for fH2S (drawn line) not to increase beyond the bubble point pH2S value (dashed line), the pH2S-bubble point approach is conservative, but at P above the intersection of these curves it no longer is. Using fH2S to characterize severity is then clearly more appropriate. From Figure 3 it may be gleaned that these conditions may already occur when P exceeds about 350 bar (35,000 kPa), a value not uncommon in HPHT wells. An assessment including non-linear thermodynamics is therefore strongly recommended for oil wells of this type to maintain at least some degree of conservatism.

FIGURE 3.

H2S fugacity and partial pressure, calculated as a function of total pressure for a 45:45:10 molar mixture of methane:decane:water; H2S partial pressure is capped at the bubble point value (dashed horizontal line).

FIGURE 3.

H2S fugacity and partial pressure, calculated as a function of total pressure for a 45:45:10 molar mixture of methane:decane:water; H2S partial pressure is capped at the bubble point value (dashed horizontal line).

The Way Forward

Even though from a thermodynamic perspective it is natural to use fH2S as a parameter to characterize the severity of a corrosive environment with respect to H2S, the experimental, quantitative proof is still partial only. Considering the complexity of a corrosion cracking mechanism, be it SSC or sour SCC, capturing the non-ideal effects of high pressure in the single parameter of fH2S seems an optimistic proposal. Also, the test work so far has not been able to clearly distinguish between fH2S and xH2S-aq as the dominant parameter. Nevertheless, the gains demonstrated by using fH2S warrant the pursuit of further progress in this direction. This may include the following items:

  • Extending experimental programs to other degradation modes, mechanisms, and materials

  • Upgrading and standardizing thermodynamic equation of state models

  • Improving field assessment of H2S

  • Defining or adapting laboratory materials qualification methods

  • Upgrading current industry guidance and standards, including NACE MR0175/ISO 151563  and NACE TM0177.5 

This paper has demonstrated the need for including non-ideal thermodynamics in materials qualification for today’s sour oil and gas production environments, in particular at high pressure.

  • The classic H2S partial pressure approach based on the ideal gas law falls short in providing improved fitness for service assessments of materials.

  • Using H2S fugacity has been shown to be valid for sulfide stress cracking, while using the H2S concentration in the corrosive water phase may also be justified.

  • There is a need to include materials and degradation modes other than SSC of steel in the model validation studies as well.

  • To facilitate the definition of the corrosive severity of laboratory and field H2S environments, proper thermodynamic models are essential.

  • Qualification test methods and materials selection standards are to be upgraded and adapted.

The purpose of the present and proposed work is to facilitate and develop materials qualification methods that adequately ensure safe field performance for current and future harsh oil and gas production conditions.

Thanks are due to Brian Chambers, Ray French, Manuel Gonzalez, Bill Grimes, and Bruce Miglin (Shell Projects and Technology, Houston, TX USA and Amsterdam, NLD).

1.
S.
Huizinga
,
M.A.
Gonzalez
,
A.
Dominik
,
J.
Hassell
,
B.P.
Miglin
,
V.
Subramanian
,
B.D.
Chambers
,
D.
Raghu
,
“Fit for Purpose Qualification of Casings in HPHT Service—A Multi-Disciplinary Approach,”
CORROSION 2015, paper no. 5594
(
Houston, TX
:
NACE International
,
2015
).
2.
W.D.
Grimes
,
R.I.
McNeil
,
“Prediction of Hydrogen Sulfide and Carbon Dioxide in HPHT Wells,”
SPE HPHT Advanced Technology Symposium, paper no. SPE 97568
(
Richardson, TX
:
SPE
,
2005
).
3.
ANSI/NACE MR0175/ISO 15156
(
2015
),
“Materials for Use in H2S-Containing Environments in Oil and Gas Production”
(
Geneva, Switzerland
:
ISO
,
2015
).
4.
F.
Song
,
S.
Huizinga
,
L.
Skogsberg
,
J.
Stockman
,
M.E.
Wilms
,
J.
Smit
,
E.
Caldwell
,
“Qualification of Super 13Cr-110 in HPHT Sour Well Service with Concentrated Brines,”
CORROSION 2016, paper no. 7126
(
Houston, TX
:
NACE
,
2016
).
5.
NACE TM0177
,
“Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H2S Environments”
(
Houston, TX
:
NACE
,
2015
).
6.
W.D.
Grimes
,
R.N.
French
,
B.P.
Miglin
,
M.A.
Gonzalez
,
B.D.
Chambers
,
“The Physical Chemistry Nature of Hydrogen Sulfide Gas as it Affects Sulfide Stress Crack Propagation in Steel,”
CORROSION 2014, paper no. 3870
(
Houston, TX
:
NACE
,
2014
).
7.
J.D.
Ramshaw
,
J. Chem. Edu.
72
,
7
(
1995
):
p
.
601
.
8.
B.D.
Chambers
,
S.
Huizinga
,
M.
Yunovich
,
R.N.
French
,
W.D.
Grimes
,
M.E.
Wilms
,
“Laboratory Simulation of Oil and Gas Field Conditions: Important Phase Behavior Considerations and Approaches,”
CORROSION 2014, paper no. 4285
(
Houston, TX
:
NACE
,
2014
).
9.
W.D.
Grimes
,
M.E.
Wilms
,
B.D.
Chambers
,
S.
Huizinga
,
“Conservatism in Sour Testing with Hydrogen Sulfide Partial Pressure Exposures—Toward a More Consistent Approach,”
CORROSION 2015, paper no. 6050
(
Houston, TX
:
NACE
,
2015
).
10.
A.
Kumar
,
J.L.
Pacheco
,
S.K.
Desai
,
W.
Huang
,
R.V.
Reddy
,
W.
Sun
,
C.A.
Haarseth
,
“Selecting Representative Laboratory Test Conditions for Mildly Sour Sulfide Stress Corrosion (SSC) Testing,”
CORROSION 2014, paper no. 4243
(
Houston, TX
:
NACE
,
2014
).
11.
E.W.
Lemmon
,
M.L.
Huber
,
M.O.
McLinden
,
NIST Reference Fluid Thermodynamic and Transport Properties—REFPROP
,
NIST Standard Reference Database 23
(
Gaithersburg, MA
:
National Institute of Standards and Technology
,
2013
).

Author notes

Based on a presentation given at the Research Topical Symposium on at CORROSION 2016 in Vancouver, British Columbia, Canada.