Gas phase H2S partial pressure (PH2S) is associated with sulfide stress cracking (SSC) and is routinely used as the “scalable” parameter to qualify materials for high-pressure, high-temperature (HPHT) wells. Candidate materials for HPHT wells routinely require ANSI/NACE MR0175/ISO 15156 compliance because a few mole ppm of H2S at high pressure may place the well beyond the 0.05 psia (0.3 kPa) sour service threshold. PH2S has been accepted historically as the scalable sour severity parameter. However, as the total pressure increases, the relationship between PH2S and the dissolved H2S concentration becomes nonlinear. This limits the robustness of PH2S as the sour severity metric. Thus, ISO 15156-1:2020 now permits the use of H2S fugacity (fH2S), H2S activity (aH2S), and H2S aqueous concentration (CH2S) as alternatives for sour testing. This recent revision is based on evidence that fH2S and CH2S each provide better correlations to SSC at elevated total pressures than PH2S. This paper will address the merits and challenges of using fH2S or CH2S to define sour severity: we argue that CH2S is a practical, experimentally verifiable approach, which can be used to validate ionic-equation of state frameworks used to characterize mildly sour HPHT environments.

Candidate materials for high-pressure, high-temperature (HPHT) wells routinely require ANSI/NACE MR0175/ISO 15156-2:20201  (herein referred to as the Standard) compliance,(1) because a few mole ppm of H2S present in the hydrocarbon phase multiplied by the total wellbore pressure is all that is required to place a well beyond the 0.05 psia (0.3 kPa) sour service threshold defined by the Standard. In the original NACE MR-01-75 standard, first drafted in 1975, material hardness limits were required for oil and gas production environments containing >0.05 psia H2S to avoid SSC, a low-temperature phenomenon (please refer to Figure 1 and Historical Approach to Mitigating SSC—Ideal Gas Behavior section for a description of the SSC mechanism). In subsequent years, the scope of the Standard was expanded to include H2S-influenced, active path stress corrosion cracking (SCC) at elevated temperatures. However, consideration of these higher temperature phenomena is beyond the scope of this paper, with the supporting literature and discussion restricted to SSC.
FIGURE 1.

Dual Venn diagrams describing: (a) contributing factors to SSC and (b) environmental factors that influence each sour severity metric, based on currently available ionic-equation-of-state (EOS) frameworks.

FIGURE 1.

Dual Venn diagrams describing: (a) contributing factors to SSC and (b) environmental factors that influence each sour severity metric, based on currently available ionic-equation-of-state (EOS) frameworks.

Relevant sour service standards still associate H2S partial pressure (PH2S) with SSC1-4  and this parameter continues to be used to qualify materials for HPHT wells. However, there is recent evidence that SSC susceptibility correlates better with H2S fugacity (fH2S) and/or CH2S at elevated total pressures.5-7  The recent publication of ISO 15156-1:2020 now allows users the option to define environmental sour severity either by fH2S, activity (aH2S), or CH2S in addition to PH2S. These alternative sour severity metrics incorporate the thermodynamic nonideality effects on H2S partitioning between gas/liquid hydrocarbon and aqueous phases at elevated pressure, temperature, and composition. The challenge now shifts to identifying a quantitative H2S parameter that is scalable with total pressure from ambient to HPHT conditions. The current best two candidates for HPHT applications are either fH2S or CH2S. As both fH2S and aH2S are derived from the chemical potential (μH2S) and fugacity can be defined in each phase, it is sufficient to consider PH2S, CH2S, and fH2S only.8  Figure 1 shows two Venn diagrams describing (a) all the factors that influence SSC and (b) the individual environmental factors that influence each sour severity metric.

While it is widely accepted that defining sour service limits based on PH2S is problematic, there is no universal acceptance of an alternative metric. There has been significant progress in understanding the thermodynamics of H2S under HPHT conditions,5,9-12  but there are only a handful of studies linking this nonideal thermodynamic behavior to actual SSC outcomes.9-10  Last, proper risk-benefit analyses of adopting an alternative modern H2S-SSC correlation metric are scarce.13 

The critical issue is therefore to determine which parameter, fH2S or CH2S, best characterizes higher-pressure sour systems for material qualification purposes. On the one hand, several authors5-7  discuss differences in H2S solubility in high-pressure vs. low-pressure systems and the relationship between concentration, fugacity, and activity. No evidence of the controlling SSC mechanism was provided. On the other hand, Krishnamurthy, et al.,7  recognized the impact of CH2S-pH on the “mechanistic” control of SSC with respect to existing evidence and empirical modeling, but it is not a mechanistic assessment that proves the role of CH2S in SSC. Regardless, once the industry arrives at a consensus on the preferred sour severity metric, and a precise quantification of the parameter is demonstrated, its significance to SSC testing outcomes with similar accuracy will need to be established.

To further the discussion, this paper addresses the merits and challenges of the two modern approaches to defining sour severity: fH2S and CH2S. On the one hand, the computationally derived fH2S contributes to the equilibrium distribution of H2S between the nonaqueous and aqueous phases, which influences sour severity at the metal/solution interface. On the other hand, the experimentally verifiable CH2S has a direct correlation to hydrogen ingress into the metal that is a precursor to cracking. We consider CH2S as a practical, experimentally verifiable approach for material qualification in mildly sour HPHT environments, and could be used to validate alternative computationally based/nonexperimentally verifiable approaches (e.g., fH2S and aH2S). The following literature review is intended to provide clarity on this important subject and provide a logical path forward to improving material qualification testing for HPHT service conditions.

The Dilemma of Relying on PH2S for HPHT Sour Service Testing

Performing actual NACE-compliant H2S fitness for service qualification tests at full wellbore pressure is not practical for most projects. Sour service autoclaves that can safely maintain a pressure differential of >10,000 psig for 720 h are rare, costly, and have limited internal volumes. Therefore, to reduce costs and to avoid the complexities, the Standard permits sour service testing in low-pressure laboratory equipment provided that the candidate material is qualified in a suitable environment that is at least as severe as the field environment.1  This is generally accomplished by using a “test gas-containing H2S and CO2 at the same partial pressures at the intended service.”1  This approach ignores the influence of high pressure on the cracking behavior of susceptible materials. The consequence of this policy, while not fully understood at the time of adoption in 1975, results in a conservative, or possibly under-conservative, design philosophy.13  The intrinsic over-conservatism of the above NACE/ISO policy becomes consequential when selecting materials for mildly sour HPHT wells with wellbore pressures >10,000 psig.5-6,14  (The policies leading to over/under-conservative design will be addressed in the following paragraphs.)

One challenge is defining the appropriate safety margin in an SSC experiment. No standard exists to define minimum safety factors for SSC testing. Table 1 provides a proposed quantitative definition of “degrees of conservatism,” although by no means are these values absolute. It is hoped that the recent investigations examining the modern sour severity metrics will lead to a consensus.

Table 1.

Proposed “Degrees of Conservatism”

Proposed “Degrees of Conservatism”
Proposed “Degrees of Conservatism”
The minimum H2S concentration in the gas/hydrocarbon phase (yH2S) required to reach 0.05 psia H2S is shown in Figure 2 and Table 2. For a mature well with a total pressure (PT) of 300 psig (low pressure), yH2S = 160 ppm is required to exceed 0.05 psia (0.3 kPa) H2S threshold. In contrast, for a 20,000 psig well, yH2S = 2.5 ppm is merely needed to exceed 0.05 psia H2S, which may trigger additional regulatory and/or material requirements.4  Therefore, when comparing 300 psig vs. 20,000 psig, the minimum yH2S needed to reach the sour severity threshold is reduced by 64 times. A universal H2S sour service threshold based on its PH2S implies that the only sour severity factors of importance are yH2S and total pressure. This assumption is far too simplistic and often leads to over-conservatism when selecting materials for modern HPHT wells in mildly sour environments.
FIGURE 2.

Minimum yH2S needed to meet or exceed the 0.05 psia H2S criteria defined by the Standard.1 

FIGURE 2.

Minimum yH2S needed to meet or exceed the 0.05 psia H2S criteria defined by the Standard.1 

Table 2.

Minimum yH2S Needed to Maintain the 0.05 psia H2S Criterion at Multiple PT

Minimum yH2S Needed to Maintain the 0.05 psia H2S Criterion at Multiple PT
Minimum yH2S Needed to Maintain the 0.05 psia H2S Criterion at Multiple PT

The issue is confounded further because materials may be qualified for sour service at 14.7 psia (101.3 kPa) with “H2S at the partial pressure of [the] intended service.”1  Performing laboratory tests at atmospheric pressure, while maintaining the field PH2S, requires increasing yH2S. For example, a 20,000 psig HPHT well containing yH2S = 2.5 mol ppm yields a pseudo-PH2S of 0.05 psia.15  At atmospheric pressure, to maintain the 0.05 psia PH2S the test gas must contain yH2S = 3,400 mol ppm (see Table 2). If the solubility of H2S remained constant with total pressure (i.e., the gas solubility is linear with pressure) then substituting total pressure with a higher yH2S in the test gas would be inconsequential. This not the case. H2S solubility decreases with increasing total pressure by at least an order of magnitude (refer to Figure 14 as an example). Thus, qualifying materials based on equivalent PH2S may lead to over-conservatism particularly when qualifying materials for service conditions with total pressures >10,000 psig (69 MPa).5-7,12 

In addition to over-conservative design concerns, the Standard also allows for a simplification for systems whose total pressure exceeds the bubble point/saturation pressure (e.g., “gas-free wells”). The assumption is made that the severity of the environment at pressures above the bubble point can be characterized by the PH2S calculated at the bubble point, which may be nonconservative when considering the modern fH2S and CH2S approaches.8  However, with modern ionic-equation of state (EOS) frameworks readily accessible to all users, fH2S, aH2S, and CH2S can be calculated at any temperature and total pressure, rendering the bubble point approximation obsolete.

Clearly, PH2S is not an appropriate metric for HPHT material selection and design, because it over predicts the true sour severity (be it fH2S or CH2S) of the actual field conditions. Defining material sour service limits strictly based on PH2S implies that the effect of total pressure on cracking susceptibility is inconsequential. The premise that material qualification laboratory tests, conducted at atmospheric pressure, can be designed merely by decreasing the total pressure and increasing the yH2S to maintain the same PH2S expected in the field and yield an identical SSC outcome for the same oilfield material is flawed. High-pressure laboratory tests and field experience confirm that the risk of cracking is significantly lower than would be expected based on laboratory tests results performed at atmospheric pressure with the same PH2S.16  Therefore, resolution on the feasibility of implementing either fH2S or CH2S is an important contribution to improving material qualification testing for HPHT wells, although it is not the sole consideration for users.

Nevertheless, the industry needs to adopt a new realistic design metric that is fully scalable with total pressure between atmospheric pressure and 20,000 psig. An improved sour severity metric to describe HPHT environments does not imply that other environmental (including mass transport, pitting, or film formation) and/or mechanical factors are not important contributors to SSC. Rather, the authors argue that PH2S should be replaced with CH2S as the new sour service metric.(2) Preference for CH2S does not preclude the option to select fH2S or aH2S as an alternative sour severity metric, pursuant that the thermodynamic calculations are performed correctly, if so desired. The following sections provide the history and rational for adopting CH2S as the sour severity metric.

Historical Approach to Mitigating Sulfide Stress Cracking—Ideal Gas Behavior

SSC is a cathodically controlled, corrosion-based failure mechanism driven by atomic hydrogen, produced from sulfide-induced corrosion, penetrating the metal surface (Figure 3). SSC usually occurs at low to moderate temperatures (< 150°F [66°C]). The major environmental parameters influencing SSC susceptibility are the in situ pH, chloride concentration, and dissolved H2S; the degree of each individual environmental factor contributing to the SSC mechanism is material dependent.
FIGURE 3.

Simplified illustration of the environmentally assisted cracking (EAC) mechanism. EAC requires an aqueous phase in contact with the metal surface.

FIGURE 3.

Simplified illustration of the environmentally assisted cracking (EAC) mechanism. EAC requires an aqueous phase in contact with the metal surface.

In the classic SSC scenario, the source of H2S originates from the oil or gas phase(s) and then partitions from the nonaqueous phase into the aqueous phase. Within the aqueous phase, the dissolved H2S (CH2S) then migrates to the metal surface based on mass transport properties (i.e., velocity effects) preventing recombination of atomic hydrogen from proton reduction to molecular hydrogen, thereby forcing atomic hydrogen uptake into the metal. From a cracking mechanism perspective, it is either CH2S5,17  or the fH2S9-10,18  that influences SSC at the crack tip, rather than the PH2S. For convenience, however, the Standard categorizes SSC susceptibility based on PH2S as a surrogate for SSC severity induced by H2S.

The Standard partial pressure thresholds implicitly presume that the PH2S is proportional to CH2S via the Strict Henry’s Law, which assumes ideal gas behavior:

formula

where the ideal (or strict) Henry’s Law constant for H2S is IkH2S = 230 mg/L/psia (0.1 mol/L/atm) for freshwater at 75°F (24°C) and 14.7 psia (1 atm).19-21  (Refer to “Nomenclature” for all other symbols.) PH2S is a relatively accurate approximation for CH2S at room temperature and low total pressures for dilute solutions. Irrespective of the total pressure of the system, however, the sour service limits for all materials specified in the Standard are defined in terms of the partial pressures of H2S and CO2. The Standard assumes that the ideal gas behavior governs and that the influence of the hydrocarbon phase on the cracking susceptibility is negligible and can be ignored.

Figure 4 illustrates the regions of environmental severity with respect to SSC as a function of the in situ pH of the aqueous phase and the PH2S of the gas phase according to the Standard.1  The pH-PH2S relationship was intended originally for carbon and low-alloy steels (LAS) with hardness values ≤22 HRC. It has also been applied by various users to visualize/design material qualification tests and establish susceptibility to SSC boundaries of corrosion-resistant alloys (CRAs).22  It is important to note that the “environmental severity” diagram, originally proposed in 1987 by Bonis and Crolet,23  was intended to emphasize the synergistic relationship between in situ pH and PH2S under typical (atmospheric) lab conditions, as the original NACE MR-01-75 Standard did not adequately address the influence of aqueous acidity on the SSC mechanism. The authors never claimed the diagram could be used to predict SSC safe use limits of candidate materials based on matching field and lab PH2S values directly under nonambient conditions, although this practice often occurs.
FIGURE 4.

Regions of environmental severity with respect to the SSC of carbon and low alloy steels. The plot was modified to emphasize the sour service limit of 0.05 psia (0.3 kPa).1 

FIGURE 4.

Regions of environmental severity with respect to the SSC of carbon and low alloy steels. The plot was modified to emphasize the sour service limit of 0.05 psia (0.3 kPa).1 

The underlying assumptions leading to over-conservatism has been to extrapolate the strict Henry’s Law relationship to nonideal conditions at high pressure, assuming PH2S remains directly proportional to CH2S. In reality, the relationship between CH2S and PH2S is nonlinear within the HPHT domain24-25  (see Figure 5). The flatline behavior, illustrated by the solid purple line in Figure 5, coincides with exceeding the bubble point pressure.24-26 
FIGURE 5.

Simplified illustration of the ideal and real phase behavior between CH2S and the PH2S for a constant yH2S as a function of total pressure.

FIGURE 5.

Simplified illustration of the ideal and real phase behavior between CH2S and the PH2S for a constant yH2S as a function of total pressure.

The historical practice of extrapolating the strict Henry’s Law to the full wellbore total pressure was suitable and afforded reasonable safety factors for low-total pressure systems. As HPHT wells have become more prevalent and the total pressures continue to rise, the safety margins have increased significantly to the point that they are onerous and impractical based on simple PH2S calculations. While a sour service limit of 0.05 psia H2S may be appropriate for wells with low total pressures, the authors are not aware of any evidence demonstrating that 0.05 psia (0.3 kPa) H2S ought to be the sour service limit between 10,000 psig (69 MPa) and 20,000 psig (138 MPa) at 75°F (24°C).

Implications of ISO 15156-1:2020 on Modernizing Sour Qualification

Recognizing the limited relevancy of the historical “regions of environmental severity” to modern HPHT applications, various agencies involved in the maintenance of the Standard have agreed to the recent publication of ISO 15156-1:2020 which permits users the option of implementing PH2S, fH2S, aH2S, or CH2S as metrics to define environmental severity. For clarity, Table 3 categorizes the modern sour service metrics based on phase behavior and whether the parameter is directly measurable in the lab or is derived from rigorous computational modeling. While the adoption of ISO 15156-1:2020 is an important contribution and milestone, the standard does not provide clear guidance on the validity of, or how to validate, the alternative sour severity metrics.

Table 3.

Sour severity metrics recognized by the Standard(A)

Sour severity metrics recognized by the Standard(A)
Sour severity metrics recognized by the Standard(A)

PH2S still remains the de facto metric to define sour severity for a variety of reasons including historical experience, safety concerns, limited available data, and/or logistical issues with capturing and preserving field samples. To safely reduce over-conservatism for material qualification in mildly sour environments at HPHT conditions, the industry ought to adopt a universally accepted PH2S alternative that is empirically based and is fully scalable across the entire service domain. Of the metrics recognized by the Standard, a concentration-based metric is the only metric that is directly experimentally verifiable. While both fH2S and CH2S can be used to translate historical SSC material testing experience (generally obtained at total pressures <5,000 psig [34.6 MPa]) to predict SSC behavior between 10,000 psig and 20,000 psig (69 MPa to 138 MPa), CH2S allows the user to explicitly set their own margin of safety. Please refer to Table 4 for a summary of additional desired properties in a modern sour severity metric.

Table 4.

Summary of Desired Properties in a Modern Sour Severity Metric

Summary of Desired Properties in a Modern Sour Severity Metric
Summary of Desired Properties in a Modern Sour Severity Metric

Having demonstrated the limitations of using PH2S to predict H2S behavior at elevated pressures, the following sections provide a review of industry’s attempt at implementing alternative modern approaches to better correlate the nonideal behavior of H2S within the HPHT domain to actual experimental data.

Modern Approach to Mitigating Sulfide Stress Cracking—Nonideal Gas Behavior

In 2005, Nelson and Reddy compared the CH2S values predicted from the strict Henry’s Law, the Fugacity-Corrected Henry’s Law, and the Ensemble Henry’s Law equations.12  As shown in Figure 6, the Ensemble Henry’s Law provided the best correlation to the experimentally determined CH2S values. These observations were later confirmed by Kumar, et al., in 201329  at CH2S relevant for mildly sour wells. The most intriguing aspect is the CH2S remains constant between ∼1,800 psia and 10,000 psia (12.4 MPa to 69 MPa) total pressure. This phenomenon has been observed by others.24-26,30-31 
FIGURE 6.

Goodness-of-fit comparison of the three solubility equations to experimental data.12 

FIGURE 6.

Goodness-of-fit comparison of the three solubility equations to experimental data.12 

The observed dissolved H2S “saturation plateau” arises from the fact that H2S does not partition equally between the hydrocarbon and aqueous phases because H2S has limited solubility in water. Literature suggests that the “saturation plateau” of CH2S is related to the effect of increasing pressure on the liquid and the gas. Therefore, for a given yH2S, CH2S increases with increasing total pressure until an apparent “saturation plateau” is reached. Within this apparent “saturation plateau” region, the CH2S is nearly independent of total pressure;10  furthermore, it is presumed that this observation is a universal phenomenon.

Nelson and Reddy applied the Ensemble Henry’s Law approach to compare the phase behavior of a well at 10,000 psi (69 MPa) total pressure containing 1 mol% H2S (100 psia [690 kPa] H2S) and a low-pressure laboratory fitness-for-purpose (FFP) test containing exclusively 100 psia H2S.12  For their scenario, the FFP test contained 11 times more dissolved H2S than predicted in the actual well. The authors concluded that the FFP test conditions were significantly more severe than the environmental conditions anticipated in the well.12 

As mentioned several times earlier, the two competing sour severity metrics that best account for the nonideal H2S partitioning are fH2S and CH2S. These two metrics are shown graphically in Figure 7. The following sections describe the implications and practicalities of: (1) a computationally based fugacity approach to evaluate sour severity under liquid-full conditions (e.g., absence of a “gas” phase), (2) a description of the Ensemble Henry’s Law, which incorporates H2S partitioning between the nonaqueous and aqueous phases, and (3) an empirically based dissolved H2S approach.
FIGURE 7.

Illustration of the relationship between PH2S and CH2S, and the competing modern sour severity metrics: (a) in-direct fH2S-based vs. (b) direct CH2S-based.

FIGURE 7.

Illustration of the relationship between PH2S and CH2S, and the competing modern sour severity metrics: (a) in-direct fH2S-based vs. (b) direct CH2S-based.

Indirect Approach: H2S Fugacity-Sulfide Stress Cracking Correlation Metric

In an attempt to reduce over-conservatism and replicate the observed nonideal thermodynamic behavior of H2S in HPHT environments, some researchers have argued that instead of defining sour severity on the basis of PH2S, the industry ought to use fH2S.9-10  The justification for using the fugacity as the sour severity metric is its applicability to all phases, gas or liquid. Based on rigorous thermodynamic calculations, at equilibrium:
formula

Based on the iso-fugacity criterion, which is derived from the concept of equal chemical potentials (i.e., ), Grimes, et al., have argued that “the equivalent fugacity between a field and laboratory condition can be matched irrespective of the nature—gas or liquid—of the phase present in the field.”10 

Thermodynamically, the fugacity of a gas is its effective, or chemically equivalent, analog to the physical partial pressure.32  Fugacity incorporates the nonideal thermodynamic effects in the real gas that are ignored in the partial pressure derived from the ideal gas law.8  The fH2S can be expressed in the units of pressure based on the following expression:

formula

The ϕH2S value is a pressure, temperature, and compositionally dependent parameter. It is a calculated, thermodynamic coefficient that cannot be directly measured in the lab, but rather the EOS model parameters are fitted to experimental data.32  Computational modeling is currently the most commonly used approach to determine fugacity in practice as physical testing is quite expensive.

At low total pressures, ϕH2S approaches 1, which means the predicted, chemical fH2S and the physical PH2S are equal. According to the latest EOS models,10  as the total pressure increases at constant temperature ϕH2S << 1; the fH2S << PH2S. For example, at 20,000 psig and 75°F (24°C), fH2S/PH2S is approximately 1/3 when using the Shell Modified and Improved Redlich-Kwong (SMIRK) model.10  The SMIRK predictions were confirmed by in-house calculations using a commercially available ionic-EOS model—refer to Figure 8(a) for details. At isothermal conditions, the “u”-shaped fugacity coefficient’s behavior (see Figure 8[a]) with total pressure mirrors the change in the compressibility factor (Z = PV/nRT) and the change in density (Figure 8[b]) of the hydrocarbon phase with total pressure.
FIGURE 8.

Model calculations(3) performed at a WGR of 10 bbl/MMscf, 75°F (24°C), and 60 mol ppm H2S + 10 mol % CO2 + balance CH4. The water phase is chloride free. The plots show the significant variation in (a) φH2S with total pressure and temperature, (b) φH2S with hydrocarbon density and temperature, (c) the change in CH2S with total pressure and temperature, and (d) φH2S with total pressure and balance gas: CH4 (field) replaced by N2 (lab).

FIGURE 8.

Model calculations(3) performed at a WGR of 10 bbl/MMscf, 75°F (24°C), and 60 mol ppm H2S + 10 mol % CO2 + balance CH4. The water phase is chloride free. The plots show the significant variation in (a) φH2S with total pressure and temperature, (b) φH2S with hydrocarbon density and temperature, (c) the change in CH2S with total pressure and temperature, and (d) φH2S with total pressure and balance gas: CH4 (field) replaced by N2 (lab).

Should the industry adopt fH2S as an improved sour severity metric over PH2S, the user should consider the following discussion points:

  1. Under liquid-full conditions, there is evidence that fH2S is a better correlation to SSC outcomes than PH2S, and may alone be sufficient to describe the system.10,18 

  2. Neither fH2S nor ϕH2S can be measured directly; they must be calculated. This may lead to inconsistencies when comparing ϕH2S calculated from different EOS models, which are often calibrated against experimental data. Currently, there only a handful of publicly accessible H2S-H2O-salt datasets available.24-25,29,33-38 

  3. Figure 8(a) indicates that as the temperature increases, ϕH2S approaches unity (ideal behavior) at elevated total pressure. Consequently, because there is only a marginal reduction in conservatism based on fH2S, PH2S alone may be sufficient to assess sour severity at elevated temperature and total pressure.

  4. Fugacity does not directly predict H2S solubility in water: (a) the effects of high pressure (Figure 6)26,30  and (b) the effects of salinity (see the Ensemble Henry’s Law Approach [H2S Partitioning Between the Nonaqueous and Aqueous Phases] section and Figure 10 for discussion).28 

  5. A single fugacity value can correspond to multiple CH2S for hydrocarbon mixtures containing different yH2S resulting in potentially different SSC outcomes. (To be discussed in further detail in the Application of The Modern Sour Severity Metrics section.)

  6. To maintain the same level of conservatism afforded by fH2S, the user would have to replicate the field conditions exactly in the lab at full wellbore pressure. This is complicated because evaluating materials in mixed gas/oil compositions and at total pressures between 10,000 psig and 20,000 psig is difficult, may unnecessarily increase testing costs, and is generally not practical for most routine laboratory applications. For example, most labs use nitrogen as a nonflammable substitute for methane. While holding yH2S constant, substituting nitrogen for methane as the balance gas results in higher ϕH2S (see Figure 8[d]). The solubility of H2S in the “gas” has a significant effect on the solubility of dissolved H2S in the test brine.

In summary, we argue that a fugacity-based approach is applicable for many sour oilfield applications because the actual CH2S is much lower than predicted by PH2S/fH2S as demonstrated by Nelson and Reddy12  and Kumar, et al.29  We agree that fH2S provides a better representation of field conditions in the lab, which may induce more or less conservatism than classical PH2S. In addition, fugacity is particularly useful when assessing low-temperature and high-pressure environments, where ϕH2S is predicted to be <<1. However, fugacity is not the only valid design approach when assessing sour severity under HPHT well environments.

Ensemble Henry’s Law Approach (H2S Partitioning Between the Nonaqueous and Aqueous Phases)

An alternative thermodynamic approach to relying solely on the calculated fugacity coefficient utilizes the Ensemble Henry’s Law equation,39  which is an extension of the Strict Henry’s Law (Equation [1]), to correlate PH2S with CH2S at HPHT conditions. The Ensemble Henry’s Law equation39  incorporates three correction factors to predict the real H2S solubility vs. total pressure (solid purple line in Figure 5).20,40  To emphasize the aqueous (left-hand side of equation) and hydrocarbon (right-hand side of equation) based thermodynamic parameters, the equation may be written as:
formula
where γH2S is the activity coefficient, ϕH2S represents the fugacity coefficient, and exp[ξ] refers to the Poynting correction factor.8,10,26 

The advantage of the Ensemble Henry’s Law is that currently available ionic-EOS frameworks9,29-31,39,41-42  incorporate the three correction terms to predict H2S behavior under HPHT conditions. (Incorporation of three correction terms may make the thermodynamic calculations more complicated to compute, and thus subject to concomitant inaccuracies. However, unlike fH2S, the predicted CH2S can be independently verified in the lab to validate thermodynamic predictions.) When using these models, it is important to consider that, based on the derivation of the Ensemble Henry’s Law,26  the fugacity and activity contributions are inseparable when predicting gas solubility.

Modern ionic-EOS frameworks that are based on the Ensemble Henry’s Law approach can also accurately predict the salting out effect of H2S in concentrated brines.26,34  An example of this effect is shown in Figure 9. As the aqueous composition shifts from freshwater to brine, the solubility of H2S decreases by about half.
FIGURE 9.

Change in H2S solubility with salinity at 77°F (25°C) and 14.7 psia H2S.34  For reference, 0.1 mol/kg H2S is equivalent to 3,400 mg/L H2S. In the legend, MMoWP = multi-model weighted prediction.

FIGURE 9.

Change in H2S solubility with salinity at 77°F (25°C) and 14.7 psia H2S.34  For reference, 0.1 mol/kg H2S is equivalent to 3,400 mg/L H2S. In the legend, MMoWP = multi-model weighted prediction.

The Ensemble Henry’s Law approach is a significant improvement over the Strict Henry’s Law and fugacity-corrected approaches. While ionic-EOS frameworks are gaining wide industry acceptance, the models have not been fully validated within the sour HPHT domain of interest. Relying on ionic-EOS frameworks without experimental verification at total pressures >10,000 psig is a concern for the following reasons:

  1. Current ionic-EOS frameworks combine two different thermodynamic theories to describe HPHT systems: The hydrocarbon phase is described by a fugacity-based algorithm (derived from van der Waals equation), while the aqueous phase behavior is described by an activity-based algorithm26,30  (an extension of the Debye-Huckel theorem) coupled to a Poynting correction factor.32  Both algorithms use different thermodynamic parameters and incorporate numerous complex equations.43  Calculations converge when the chemical potential in the nonaqueous phase () equals the chemical potential in the aqueous phase (). The useful thermodynamic parameters (i.e., γH2S, ϕH2S, and exp[ξ]) are derived from the chemical potential, a derivative of Gibbs free energy.26 

  2. EOS models often regress thermodynamic parameters from simple, multi-dimensional systems. Unlike the CO2-H2O-salt system,43  there are only a handful of reliable H2S-H2O-salt databases available,24-25,29,33-38  and the majority of the public datasets contain experimental data up to 5,000 psig.30  The authors are not aware of any published, experimental solubility H2S-CO2-CnH2n-H2O-salt data performed above 10,000 psig.29,38 

  3. Figure 10 illustrates the complex interactions between fugacity, activity, and dissolved concentration predicted at 75°F (24°C) and 5,000 psig (34.5 MPa). In this example, as the salinity increases from 0 to 150,000 mg/L Cl, the activity coefficient (γH2S) increases from 1 to 1.6, while CH2S decreases by nearly ½. Conversely, ϕH2S remains constant (∼0.3) and thus insensitive to changes in ionic strength. Under the conditions described, fH2S is fixed, which implies aH2S is also fixed. While CH2S and γH2S vary inversely, when the two parameters are multiplied together, they should reproduce the fixed aH2S, and thus should parallel fH2S, which is also fixed. In the end, the aqueous activity (as defined here) together with the Poynting correction should deliver the same result as equating a known gas fH2S with the aqueous fH2S. It is worth noting that, in the context of SSC, salt content not only has an effect on H2S, but it also affects other aspects of the mechanism (e.g., in situ pH and film passivation of the metal oxide).(4)
    FIGURE 10.

    Model calculations(3) performed at a water gas ratio (WGR) of 10 bbl/MMscf, 75°F (24°C), 5,000 psig, and pH 3. The non-aqueous phase contains 60 mol ppm H2S, 10 mol% CO2 and balance CH4. Shows the change in γH2S, φH2S, and CH2S as a function of [Cl].

    FIGURE 10.

    Model calculations(3) performed at a water gas ratio (WGR) of 10 bbl/MMscf, 75°F (24°C), 5,000 psig, and pH 3. The non-aqueous phase contains 60 mol ppm H2S, 10 mol% CO2 and balance CH4. Shows the change in γH2S, φH2S, and CH2S as a function of [Cl].

  4. To calculate the thermodynamic parameters using current ionic-EOS frameworks in the range of 10,000 psig to 20,000 psig (69 MPa to 138 MPa) total pressure, requires significant extrapolation of the datasets to capture the CH2S typical of mildly sour HPHT wells. The concern is the experimental H2S solubility data collected to date were: (1) conducted at total pressures that are nearly half an order of magnitude lower than those expected for HPHT wells and (2) the PH2S used to calculate H2S solubility are orders of magnitude higher than those typical for mildly sour service. The technology gap between the experimental data and HPHT domain of interest is shown graphically in Figure 11.
    FIGURE 11.

    Schematic comparison between the available H2S-H2O-salt public database domain versus the HPHT sour service domain of interest.

    FIGURE 11.

    Schematic comparison between the available H2S-H2O-salt public database domain versus the HPHT sour service domain of interest.

In summary, there is insufficient data available to properly verify the accuracy of the existing ionic-EOS frameworks in environments reflective of mildly sour HPHT wells, because H2S is toxic (which limits the number of facilities able to conduct solubility research) and simulating HPHT conditions in the lab with methane as the dominant gaseous constituent is difficult. With a few exceptions, the motivation of thermodynamicists and software developers up to this point has been to primarily develop a “universal” ionic-EOS tool, not a dedicated HPHT-mildly sour service model.

Extension of the existing H2S-H2O-salt experimental database to the HPHT domain of interest is critical, but just knowing the relationship between PH2S and CH2S at HPHT conditions is not enough. To be of practical use to the industry, CH2S at full wellbore pressure must also be tied back to the material-specific SSC threshold, usually defined as the PH2S limit at normal temperature and pressure (NTP) as implied in Figure 4 for example.

Direct Approach: Dissolved H2S-Sulfide Stress Cracking Correlation Metric

A promising method to correlate HPHT sour phase behavior to low-pressure SSC tests5-6  is an empirical approach that measures CH2S. The direct approach assumes that CH2S is the parameter that influences the SSC mechanism. The dissolved H2S-SSC correlation metric rearranges the Ensemble Henry’s Law so that all thermodynamic parameters are grouped together (Equation [5]):

formula

This is simplified to Equation (6)

formula

where RkH2S represents the real (apparent) H2S Henry’s Law coefficient. The coefficient, RkH2S, has the units of mg/L/psia,(5) when PH2S is in units of psia, and CH2S has the dimension of mg/L.11,20,40 RkH2S is temperature, total pressure, hydrocarbon composition, and ionic strength dependent due to nonideal solubility effects.44  At NPT and no salt, RkH2S equals IkH2S. As total pressure increases, RkH2S decreases logarithmically with increasing total pressure; as PT approaches 20,000 psig, RkH2S << IkH2S.45 

Figure 12 is a computational example showing the overall change in RkH2S with total pressure (purple data dots). Also shown are the individual Ensemble Henry’s Law coefficients that collectively contribute to predict for a specific hydrocarbon composition containing 60 mol ppm H2S + 5 mol% CO2 in CH4 in equilibrium with freshwater at 75°F (24°C). Based on the example presented, the following observations are noted:
FIGURE 12.

Comparison of normalized individual Ensemble Henry’s Law coefficients to RkH2S for a WGR of 10 bbl/MMscft at 70°F (21°C). The modeled aqueous phase contains 0 mg/L Cl and the hydrocarbon composition contains 60 mol ppm H2S + 5 mol% CO2 in CH4.(3)

FIGURE 12.

Comparison of normalized individual Ensemble Henry’s Law coefficients to RkH2S for a WGR of 10 bbl/MMscft at 70°F (21°C). The modeled aqueous phase contains 0 mg/L Cl and the hydrocarbon composition contains 60 mol ppm H2S + 5 mol% CO2 in CH4.(3)

  • As expected, the H2S activity coefficient (γH2S) remains nearly constant and shows very little dependence on total pressure as the ionic strength of the solution remains fixed.

  • The H2S fugacity coefficient (ϕH2S) changes parabolically with increasing total pressure and reaches a minimum of approximately 1/4 near PT = 5,000 psig, before slowly rising to approximately 1/3 at PT = 20,000 psig. It could be argued that up to 5,000 psig, fugacity alone could be used to predict the total pressure effect on H2S solubility.

  • Above 5,000 psig, however, ϕH2S alone cannot replicate the change in apparent solubility behavior (RkH2S, which reaches a minimum of ∼1/25 at PT = 20,000 psig). As total pressure increases, the Poynting correction (or change in intrinsic solubility with total pressure) grows exponentially and contributes ~1/10 to the overall change in apparent solubility.

  • The predicted decreasing trend in apparent solubility coefficient (RkH2S) profile with total pressure can be experimentally verified. Experimental verification, however, requires performing a series of rigorous, experimental autoclave tests at high total pressures and temperatures, and accurately measuring the H2S concentration in both the aqueous (CH2S) and gas/liquid hydrocarbon (yH2S) phases at H2S quantities reflective of mildly sour service conditions.(6) If done properly, experimental verification of the predicted RkH2S values can be used to validate ionic-EOS frameworks, as we have demonstrated.45 

Critics13  of this approach argue that by defining sour severity based on CH2S there is the potential for higher risk because the over-conservative safety factors intrinsic to the PH2S and fH2S approaches are removed. Proponents of CH2S approach5-7,28,46  have argued that knowing the sour severity limit does not restrict the user from setting their own safety factor when qualifying materials. Typically, risk-based design tolerances are often component (e.g., primary vs. secondary pressure containment) and well (e.g., onshore vs. offshore) specific. Utilization of a dissolved H2S design approach, however, does require accurate analytical measurements and a robust experimental database to fully validate the methodology.

Before this dissolved H2S approach could be formally adopted, the effect of the CH2S on the SSC mechanism needs to be quantified and properly characterized. Because the CH2S is a requirement for SSC, the authors argue that the same parameter may also be the characterizing parameter for SSC. Evidence of a correlation between CH2S and fracture toughness as a function of total pressure have already been demonstrated.10,14  In the absence of additional experimental data, fugacity remains the more conservative approach.8,10,13  Resorting to a CH2S-SSC correlation metric can only be justified by understanding its role in the SSC mechanism, not just by measuring concentrations.(7)

In summary, despite the many challenges, the benefits of the CH2S design approach are substantial, and this approach is already being recommended for low-cost, high-pressure wells, with the caveat that accurate H2S measurements in the field must be obtained.7 

A hypothetical sour service example is used to demonstrate the utility of the dissolved H2S approach. In the following example, a producer well has a water gas ratio (WGR) of 10 bbl water per 1 MMscf gas. The hydrocarbon phase is composed of 60 ppm H2S + 10 mol% CO2 + balance CH4 and the gas is assumed to be comingled with freshwater containing 0 mg/L Cl. Modern ionic-EOS calculations(3) predict the following sour service metrics at 20,000 psig and 75°F (24°C): 1 psia (6.9 kPa) PH2S (hydrocarbon) ≡ 0.32 psia (2.2 kPa) fH2S ≡ 12 mg/L H2S (aqueous). The implications of each sour severity metric are discussed below.

If a 20,000 psig autoclave is available for material qualification, then regardless of the sour severity metric selected, the same SSC outcome is expected. As mentioned earlier, there are several logistical problems related to utilizing autoclaves rated to 20,000 psig. As such, users often prefer using low-pressure rated equipment to qualify materials. Designing an SSC qualification test with an exposure gas of PH2S = 1 psia at PT = 1 atm may place a severe restriction on available material options for users.(7)

Alternatively, candidate materials could be qualified at fH2S  = 0.32 psia.(7) When designing an SSC material qualification test using low-pressure rated equipment and matching lab sour severity based on equivalent fH2S predicted for the HP field environment, the following factors should be considered: (1) the ϕH2S varies with total pressure9  (refer to Figure 8[a]), (2) the CH2S also changes with total pressure and its behavior is independent of ϕH2S, and (3) a single fH2S value can correspond to multiple CH2S, which may lead to different cracking outcomes. Figure 13 shows the change in CH2S with total pressure at three different yH2S ranging from 60 ppm to 240 ppm. As the total pressure exceeds the bubble point pressure, the CH2S levels off. At 18,000 psig (124 MPa) and at 60 ppm yH2S, fH2S = 0.32 psia and CH2S = 12 mg/L. This same fH2S = 0.32 psia value also corresponds to CH2S = 23 mg/L at PT = 11,300 psia (78 MPa; yH2S = 120) and CH2S = 45 mg/L at PT = 4,700 psig (32.4 MPa; yH2S = 240 ppm).

A single fugacity value corresponding to multiple CH2S is of concern as the Standard1  assigns material-specific PH2S limits indiscriminate of total pressure. While a single CH2S can also correspond to multiple fH2S values, mathematically the inverse operation is noncommutative as SSC is ultimately dependent upon the H2S content of the aqueous phase. To be meaningful, the fH2S threshold must be reported with the specific PVT reference state used to make the thermodynamic calculations and to correctly design material qualification tests in the laboratory.

Alternatively, SSC qualification tests could be designed by matching the field and laboratory conditions based on equivalent CH2S. Figure 14 shows the predicted relationship between CH2S and total pressure for a hypothetical well producing gas containing 60 ppm yH2S. At 20,000 psig (138 MPa), the well is exposed to a PH2S of 1 psia (6.9 kPa), which is predicted to be equivalent to CH2S = 12 mg/L.
FIGURE 13.

Relationship between predicted(3) fH2S and CH2S at multiple yH2S values assuming 10 bbl/MMscf, 0 mg/L Cl, and 75°F (24°C).

FIGURE 13.

Relationship between predicted(3) fH2S and CH2S at multiple yH2S values assuming 10 bbl/MMscf, 0 mg/L Cl, and 75°F (24°C).

One reservation against adopting a dissolved H2S-based sour service metric is CH2S is meaningless to most users. To make 12 mg/L CH2S meaningful, and to correctly interpret SSC qualification test results that are often evaluated using low-pressure rated equipment, the CH2S expected under HPHT conditions ought to be translated to the equivalent PH2S at NTP.

Figure 15 shows the predicted relationship between CH2S and PH2S at 75°F (24°C). At 20,000 psig, (kH2S)20k  = 10.8 mg/L/psi. At 14.7 psia, (kH2S)atm = 230 mg/L/psi, a factor of 20 times different. The concentration of 12 mg/L H2S(aq) corresponds to (PH2S)20K = 1 psia. This same 12 mg/L concentration corresponds to a (PH2S)atm = 0.05 psia (0.3 kPa). In other words, in terms of expected SSC outcomes, testing at 0.05 psia (PH2S)atm may be equivalent to testing at 1.0 psia (PH2S)20K, if indeed CH2S is the mechanistically correct metric.(6)
FIGURE 14.

Relationship between predicted(3) total pressure and CH2S at 60 mole ppm yH2S assuming 10 bbl/MMscf, 0 mg/L Cl, and 75°F (24°C).

FIGURE 14.

Relationship between predicted(3) total pressure and CH2S at 60 mole ppm yH2S assuming 10 bbl/MMscf, 0 mg/L Cl, and 75°F (24°C).

Based on the above observations, the authors refer to this as the CH2S-SSC Scalability Paradigm:

Materials tested at equivalent CH2S will yield the equivalent SSC outcome, regardless of total system pressure, where all other factors being equal.

If our paradigm is correct, then the “environmental severity” diagram could be calibrated for both (PH2S)atm and the equivalent predicted pseudo-(PH2S)20k. Such a hypothetical diagram is shown in Figure 16 at 0 mg/L Cl and 75°F (24°C). For example, 0.05 psia (PH2S)atm has equivalent sour severity as the predicted 1.0 psia (PH2S)20k. The link between the two total pressure domains is CH2S.
FIGURE 15.

A comparison of the calculated(3) H2S solubility coefficients at atmospheric pressure (blue slope) and 20,000 psig (purple slope) at pH 4 and 75°F (24°C) + 0 mg/L Cl.

FIGURE 15.

A comparison of the calculated(3) H2S solubility coefficients at atmospheric pressure (blue slope) and 20,000 psig (purple slope) at pH 4 and 75°F (24°C) + 0 mg/L Cl.

Instead of correlating SSC susceptibility based on PH2S and in situ pH, the “environmental severity” diagram could be revised with PH2S (x axis) being replaced with CH2S as demonstrated in Figure 17. In this arrangement, the equivalent (PH2S)atm and (PH2S)20K thresholds shown separately in Figure 16 are now combined into a single plot. The proposed “environmental severity” diagram now allows the user to quickly convert field PH2S to an equivalent atmospheric test value. The challenge now is to provide experimental confirmation at 20,000 psig.(6)
FIGURE 16.

A comparison of the ANSI/NACE MR0175/ISO 15156 regions of environmental severity for SSC at both NPT and 20,000 psig at 75°F. Calculations(3) at 20,000 psig were made based on the proposed CH2S-SSC scalability paradigm at 75°F (24°C). WGR = 10 bbl/MMscf: 0 mg/L Clwith the nonaqueous phase containing 60 mol ppm H2S + 10 mol% CO2 + bal. CH4.

FIGURE 16.

A comparison of the ANSI/NACE MR0175/ISO 15156 regions of environmental severity for SSC at both NPT and 20,000 psig at 75°F. Calculations(3) at 20,000 psig were made based on the proposed CH2S-SSC scalability paradigm at 75°F (24°C). WGR = 10 bbl/MMscf: 0 mg/L Clwith the nonaqueous phase containing 60 mol ppm H2S + 10 mol% CO2 + bal. CH4.

FIGURE 17.

Hypothetical regions of environmental severity for SSC based on CH2S and in situ pH under the same environmental conditions described in Figure 16. Dashed CH2S lines represent the equivalent predicted(3) PH2S at atmospheric pressure (blue values) and 20,000 psig (green values). This diagram is of the authors’ opinion and is a proposed change to the Standard.1  This is not an endorsement by the NACE MR0175/ISO 15156 Maintenance Panel nor other regulatory body.

FIGURE 17.

Hypothetical regions of environmental severity for SSC based on CH2S and in situ pH under the same environmental conditions described in Figure 16. Dashed CH2S lines represent the equivalent predicted(3) PH2S at atmospheric pressure (blue values) and 20,000 psig (green values). This diagram is of the authors’ opinion and is a proposed change to the Standard.1  This is not an endorsement by the NACE MR0175/ISO 15156 Maintenance Panel nor other regulatory body.

An important limitation to note is Figure 17 does not account for the effect of temperature and could pose problems when translating from a HP field to an equivalent lab condition. Because SSC is a low-temperature phenomenon, however, the temperature range of interest is narrow. Based on the calculations shown in Figure 8(c), between 77°F and 200°F (25°C to 93°C) the predicted CH2S barely changes for a fixed yH2S. Thus, the concern is not at high temperatures, but rather applying the proposed diagram to assess SSC risks at temperatures <70°F (21°C). Gas solubility is known to increase with decreasing temperature. The resolution is to generate an equivalent diagram at 40°F (4°C), which is generally accepted as the lower service temperature of an offshore well at the seafloor.

Much work is needed before submitting a formal Ballot to the NACE MR0175/ISO 15156 Maintenance Panel to revise the historically accepted definition of “environmental severity” based on PH2S to one based on CH2S. A concerted effort to experimentally verify the behavior of H2S under HPHT conditions relevant to the oilfield is underway.45  Verification of the CH2S-SSC scalability paradigm requires the use of high-pressure equipment up to 20,000 psig, and H2S toxicity concerns must be handled with care. Accurate analytical documentation of the exposure environment must be provided to irrefutably link CH2S to the cracking behavior of high-strength materials at multiple total pressures. For this benchmark study, materials with controlled chemistries, microstructures, and mechanical properties are recommended.

While the challenges to validating the CH2S-SSC scalability paradigm are steep, they are not insurmountable, and the potential rewards are much higher. In fact, there is already reliable research on this important topic. In 2018, Chambers, et al.,14  exposed T95 carbon steel in multiple continuous-liquid-loaded autoclaves, which were elegantly designed to deliver equal CH2S at increasing total pressures (from 14.7 psig to 10,000 psig) for 30 d. The fracture toughness of the material reportedly increased with increasing total pressure beyond statistical uncertainty, although the results were not expected and the authors noted several experimental complications.14  Further investigation is warranted to confirm the test results independently, and to possibly extend the application to additional metallurgies.

Having thoroughly described a process to validate the CH2S-SSC scalability paradigm, our plan is to spearhead an ambitious multi-year testing program to prove our hypothesis. The benefit to operators is the justification to safely select less expensive materials, traditionally considered marginal, as suitable candidates for mildly sour HPHT environments without the risk of failure by SSC. For material manufacturers, validating the paradigm will expand the application of existing products to new sour service applications. In conclusion, confirmation of the paradigm will reduce material qualification testing costs for most applications as low-pressure rated equipment (e.g., <5,000 psig) could be used to reliably predict SSC behavior under HPHT conditions (i.e., 10,000 psig to 20,000 psig).

As accurate CH2S and yH2S measurements alone are insufficient to demonstrate validity of this approach to characterize severity in the specific SSC context, the authors have recently performed a limited number of SSC tests with 15Cr-125 martensitic stainless steel (MSS) in batch-loaded autoclaves up to 20,000 psig and 70±5°F (21±3°C). To investigate the causal relationship between CH2S and SSC, all environmental conditions were held constant (including a fixed molar inventory of H2S) per autoclave test, with exception of increasing the total pressure with additional N2 booster gas. To date, the unpublished results are consistent with our CH2S-SSC scalability paradigm: i.e., the severity of the physical damage induced by SSC (in terms of both cracking and pitting features) are closely related to the measured CH2S and independent of the measured yH2S/pseudo-PH2S at increasing PT. We plan to present our findings in a future publication.

On a final note, it is recognized that capitalizing on all of these advantages cannot be done cavalierly. While there are obvious “capital expenditure” advantages in terms of more affordable materials if SSC is controlled by CH2S, caution needs to be applied in confirming this fact and broad applicability must be demonstrated before the “cost” advantages are fully realized.

  • While PH2S may be appropriate for assessing sour severity for low-pressure wells, it is not a predictive parameter within the HPHT domain, because the relationship between PH2S and CH2S deviates from simple proportionality. Defining sour service qualification parameters based on PH2S for materials intended for HPHT application generally leads to over-conservatism.

  • ISO 15156-1:2020 now permits users the option of implementing either the PH2S, fH2S, aH2S, or CH2S as metrics to define environmental severity. Of the metrics recognized by the standard, CH2S is the only modern metric that is directly experimentally measurable.

  • A CH2S-SSC paradigm could be used to translate historical SSC material testing experience (generally obtained at total pressures <5,000 psig [34.5 MPa]) to predict SSC behavior between 10,000 psig and 20,000 psig (69 MPa to 138 MPa). Such a strategy could also be adopted for other modern sour severity metrics as well.

  • While both fH2S and CH2S design metrics can be used to predict sour severity under HPHT conditions, thermodynamic predictions should be verified with physical testing. In the absence of additional experimental data, however, fH2S remains the more conservative approach, pursuant the thermodynamic calculations are performed correctly using a validated ionic-EOS framework.

  • Solving the Ensemble Henry’s Law equation for CH2S as written requires the use of sophisticated ionic-EOS frameworks. However, extending the use of these frameworks to the mildly sour and high total pressures requires significant extrapolation (with concomitant inaccuracies) of currently available H2S-H2O-salt databases.

  • When thermodynamic correction factors are combined with the Strict or Ideal Henry’s Law constant into a single H2S solubility term, the resulting RkH2S can be experimentally confirmed. As a secondary benefit, if RkH2S values are experimentally confirmed, this implies confirmation of the fugacity EOS models as well.

  • For a given sour gas composition, the predicted relationship between CH2S and PT showed CH2S remained nearly constant from approximately 1,800 psig PT out to 20,000 psig, rendering CH2S as a potential scalable H2S-SSC parameter candidate.

  • In the absence of experimental confirmation, however, caution needs to be applied when considering the implications of applying the dissolved H2S approach.

(1)

The ramifications for categorizing a well as sour are profound, because while the Standard1  is not a regulatory document per se, it has been incorporated by reference in its entirety by many regulatory agencies worldwide, and for many jurisdictions its technical definitions and requirements carry the compulsion of a regulatory writ.

(2)

On the one hand, selecting materials based on a conservative design criterion is critical to ensure safety. However, there is a distinction between adopting a mechanistically consistent, fully-scalable sour service metric, and applying an appropriate margin of safety to account for system uncertainty. On the other hand, for field application, independent of the actual SSC mechanism, it is critically important to quantitatively understand the sour severity predictions per metric, and particularly with respect to the relative degree of conservatism between metrics that could be used.

(3)

In-house ionic-EOS calculations were performed using OLI MSE-SRK v. 9.6.2 throughout.

(4)

While there may be advantages to use a sour severity metric that is insensitive to ionic strength (i.e., fH2S of aH2S), it may be problematic when predicting material performance of CRAs, which are generally sensitive to a combination of H2S, in situ pH, and/or [Cl].

(5)

Following the United States customary (USC) units convention.

(6)

An experimentally based H2S solubility study, under relevant HPHT well conditions, is ongoing at the author’s state-of-the-art sour testing lab. The program includes both H2S solubility measurements up to 20,000 psig45  and performing accompanying SSC tests of high-strength materials to collaborate our thermodynamic calculations.

(7)

A critical point to consider is if this approach adequately reproduces the environmental severity of the actual sour service conditions. If so, the mentioned restrictions would be valid; if not, an alternative is called for.

The authors wish to thank Honeywell Corrosion Solutions (Houston, TX) for its support of time and underwriting this study. A.J. Gerbino, OLI Systems, Inc., is gratefully acknowledged by the authors for his guidance and continued support of the research. The authors would also like to acknowledge the thorough analysis and thoughtful critique provided by the reviewers.

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NOMENCLATURE

     
  • ai

    Activity of i in the aqueous phase, mol/L

  •  
  • Ci

    Dissolved i concentration in the aqueous phase, mg/L

  •  
  • fi

    Fugacity of i in the gas phase, psia

  •  
  • i

    Component

  •  
  • ki

    Henry’s constant of i solubility, mg/(L·psia)

  •  
  • ni

    Number of i moles in gas phase, mol

  •  
  • Pi

    Partial pressure of i, psia

  •  
  • PT

    Total pressure, psig

  •  
  • R

    Ideal gas constant, 8.3144 J/(mol·K)

  •  
  • T

    System temperature, K or °F

  •  
  • V

    Volume of the gas phase, L

  •  
  • xi

    Mole fraction i in the aqueous phase, mol%

  •  
  • yi

    Mole fraction of i in gas/liquid hydrocarbon phase, mol% (mol ppm)

  •  
  • γi

    Activity coefficient of i in the aqueous phase—Corrects for the nonideal behavior of i in the aqueous phase

  •  
  • ξi

    The Poynting correction factor is often expressed as an exponential term related the partial molar volume of i. It adjusts for the effect of total system pressure on the solubility of i in the aqueous phase

  •  
  • μi

    Chemical potential of i, J/mol—fundamental parameter derived from Gibbs free energy

  •  
  • i

    Fugacity coefficient of i in the gas phase—a correction for nonideal behavior of H2S in the hydrocarbon phase