Environmental Parameters

PREDICT evaluates a large number of environmental parameters to assess the corrosive severity of the environment and to determine a corrosion rate in steels. PREDICT also assists you in determining the viability of carbon steels through a rigorous evaluation of general corrosion susceptibility of steels with or without inhibition in the operating environment. The system determines a steel corrosion index, a number representing the predicted corrosion rate in the operating environment.

PREDICT uses a large number of parameters to determine the steel corrosion severity index. The system uses a widely accepted CO₂-based corrosion prediction model to obtain an initial assessment of corrosion severity in carbon steels. This number is modified to account for the effects of other factors such as temperature, H₂S, chlorides, velocity and inhibition. Relevant parameters in steel evaluation include,

Carbon dioxide (CO2)

CO₂ is one of the most important parameters in determining corrosivity of a production environment. CO₂-based corrosion has been one of the most active areas of research, with several predictive models for carbon steel corrosion assessment. These efforts range from a predictive model that begins with CO₂ corrosion to models that focus on specific aspects of the corrosion phenomena (such as flow-induced corrosion or erosion corrosion) to models that empirically relate corrosion rates to gas production and water production rates.

The Predict model integrates lab data and field experience within the framework of relevant controlling parameters that are most prominent in oil and gas production. While there have been several studies focusing on the exact mechanism of metal dissolution in CO₂ containing waters, the efforts of De Waard and Milliams and others present a commonly accepted representation wherein anodic dissolution of iron is a pH dependent mechanism as given by Bockris, the cathodic process is driven by the direct reduction of undissociated carbonic acid. These reactions can be represented as,

Fe ----------> Fe⁺⁺ + 2e^-(Anodic reaction)

H₂CO₃ + e^-----> HCO₃^- + H (Cathodic reaction)

The overall corrosion reaction can be represented as,

Fe + 2H₂CO₃ ---> Fe++ + 2 HCO₃^- + H₂

The build up of the bicarbonate ion can lead to an increase in the pH of the solution till conditions promoting precipitation of iron carbonate are reached, leading to reaction given below:

Fe + 2HCO₃^- ---> FeCO₃+ H₂O+CO₂

Iron carbonate solubility, which decreases with increasing temperature, and the consequent precipitation of iron carbonate is a significant factor in assessing corrosivity. This corrosion rate equation is given as²,

log (V_cor) = 5.8 - 1710/T + 0.67 log (pCO₂) ------ (1)

where

V_cor = corrosion rate in mm/yr

T = operating temperature in K

pCO₂ = partial pressure of CO₂ in bar

The corrosion rate obtained by equation (1) has typically been often seen as the maximum possible corrosion rate without accounting for iron carbonate scaling. A nomogram representing eq. (1) is given in Figure 1, which also includes a scale factor to account for the formation of protective carbonate films that lead to a reduced corrosion rate at higher temperatures.

pH (Hydrogen Ion Concentration)

pH is one of the most critical parameters in corrosivity determination. For production environments, where it is the dissolved CO₂ or H₂S that contribute significantly to a lower pH, pH can be determined as a function of acid gas partial pressures, bicarbonates and temperature, as shown in Figure 3 [23]. From a practical stand point, the contribution of H₂S or HCO₃ or temperature to pH determination is another way of representing effective levels of CO₂ that would have produced a given level of pH.

While it has been documented that the CO₂ corrosion mechanism is dissimilar to that of strong acids like HCl (where as CO₂ corrosion is now understood to progress through direct reduction of H₂CO₃ to HCO₃^- rather than reduction of H⁺ ions), and that carbonic acid corrosion is much more corrosive than that obtained from a strong acid such as HCl at the same pH, there is also significant agreement that lower pH levels obtained from higher acid gas presence leads to higher corrosion rates. Conversely, higher levels of pH obtained through buffering in simulated production formation water solutions have been shown to produce significantly lower corrosion rates even at higher levels of CO₂ and/or H₂S. Data about the effects of pH from another study is shown in Figure 4. Hence, it is more meaningful to determine the effective CO₂ partial pressure from the system pH. Data in Figure 3 can be represented as equations for straight lines in terms of pH and acid gas partial pressures for a given level of HCO₃ and temperature. The Predict system incorporates a numerical computer model to compute pH for different values of acid gas partial pressures, HCO₃ and temperature.

Hydrogen Sulfide (H2S)

Oilfield production environments, in recent years, have been characterized by increasing presence of H₂S and related corrosion considerations. Even though H₂S is probably the most significant concern in current day corrosion and cracking evaluation, the role of H₂S in corrosion in steels has received much less attention when compared to the widely studied CO₂ corrosion. However, H₂S related corrosion and cracking has remained one of the biggest concerns for operators involved in production because of the significance of H₂S related damage.

The Predict model, in addition to its contribution in pH reduction, provides a three fold role for H₂S:

1. At very low levels of H₂S (< 0.01 psia), CO₂ is the dominant corrosive species, and at temperatures above 60 C, corrosion and any passivity is a function of FeCO₃ formation related phenomenon and the presence of H₂S has no realistic significance.
2. In CO₂ dominated systems, presence of even small amounts of H₂S (ratio of pCO₂/pH₂S > 200), can lead to the formation of an iron sulfide scale called mackinawite at temperatures below 120 C. However, this particular form of scaling, which is produced on the metal surface directly as a function of a reaction between Fe⁺⁺ and S^{- -} is influenced by pH and temperature. This surface reaction can lead to the formation of a thin surface film that can mitigate corrosion. The stability and formation of such films called mackinawite is the subject of much research.
3. In H₂S dominated systems (ratio of pCO₂/pH₂S < 200), there is a preferential formation of a meta-stable sulfide film in preference to the FeCO₃ scale; hence, there is protection available due to the presence of the sulfide film in the range of temperatures 60 to 240 C. Here, initially it is the mackinawite form of H₂S that is formed as a surface adsorption phenomenon. At higher concentrations and temperatures, mackinawite becomes the more stable pyrhotite. However, at temperatures below 60 C or above 240 C, presence of H₂S exacerbates corrosion in steels since the presence of H₂S prevents the formation of a stable FeCO₃ scale. Further, it has been observed that FeS film itself becomes unstable and porous and does not provide protection. Also, the scale factor applicable for CO₂ corrosion with no H₂S (shown in Figure 1) becomes inapplicable. Even though there is agreement amongst different workers that there is a beneficial effect of adding small amounts of H₂S at about 60 C, Ikeda et al.[9] and Videm et al.[11] present divergent results at higher concentrations and higher temperatures.

The effect of H₂S adopted in the Predict model reflects work published by T. Murata et al. for CO₂ dominated systems. Figure 5 [29] shows the combined effects of temperature and gas composition on corrosion rate of carbon steels. Figure 6 [9] shows the effect of varying degrees of H₂S contamination on CO₂ corrosion. It is to be noted that the role of H₂S in CO₂ corrosion is a complex issue governed by film stability of FeS and FeCO₃ at varying temperatures and is an area further active research.

Bicarbonates

The bicarbonate ion is a buffering agent used in aqueous solutions to increase the pH of the solution. Its presence is typically measured in mili-equivalents/liter (meq/l). One meq/l represents 0.061 grams of HCO3 in one liter of solution. The reduction in pH in turn decreases the corrosivity of the environment.

Bicarbonates in the operating environment have a significant impact on corrosion rates. On one hand, high levels of bicarbonates can provide higher pH numbers leading to corrosion mitigation even when the partial pressures of CO₂ and H₂S are fairly high. There is a natural inhibitive effect of presence of bicarbonates which can be present in substantial quantities in formation waters (up to 20 meq/l)³¹. Condensed water in production streams typically contains no bicarbonates.

Chlorides

Produced water from hydrocarbon formations typically contains varying amounts of chloride salts dissolved in solution. The chloride concentration in this water can vary considerably, from zero to few ppm for condensed water to saturation in formation waters having high total dissolved salts/solids (TDS). In naturally deaerated production environments, corrosion rate increases with increasing chloride ion content over the range 10,000 ppm to 100,000 ppm³⁰. The magnitude of this effect increases with increasing temperature over 60 C (150 F). This combined effect results from the fact that chloride ions in solution can be incorporated into and penetrate surface corrosion films which can lead to destabilization of the corrosion film and lead to increased corrosion. This phenomenon of penetration of surface corrosion films increases in occurrence with both chloride ion concentration and temperature. Chlorides are often specified in ppm NaCl. It should be noted that ppm chlorides can be obtained as 0.63 x ppm NaCl.

Under normal circumstances, the chloride content of the aqueous phase does not directly affect the hydrogen charging conditions in steel. However, it can also affect the effectiveness of chemical corrosion inhibitors. Therefore, in many cases, more careful selection of inhibitors and inhibition procedures must be performed where high levels of chlorides (>30,000 ppm) are present.

Corrosion rates of steel in oil and gas production generally increase with increasing chloride content. The chloride species in the aqueous phase can work to penetrate and destabilize protective surface films. Typically, brines with low chloride content (i.e. <10,000 ppm) are less aggressive than those having higher chloride contents provided that they are compared at the same pH. In some cases, the presence of salts can reduce the solubility of acid gases or buffer the water and may therefore alter the solution pH.

Operating Temperaure

Temperature has a significant impact on corrosivity in CO₂/H₂S systems. Corrosion rate as a function of different levels of CO₂ and temperature are given in Figure 7 [2]. It has to be noted that once the corrosion products are formed, there is a significant mitigation in corrosivity. It is also apparent that the carbonate film is more stable at higher temperatures and affords greater protection at higher temperatures. Figure 7 also shows that at temperatures beyond 120 C, corrosion rate is almost independent of the CO₂ partial pressure of the system. The carbonate film may, however, be weakened by high chloride concentrations or can be broken by high velocity. In H₂S dominated systems, because of the fact that no carbonate scale may be formed and that the FeS film becomes porous and unstable at temperatures beyond 120 C, significant localized corrosion may be observed.

Gas to Oil Ratio

In oil and gas production, where the environment has a GOR < 890 m3/m3 (5000 scf/bbl in British units), the tendency for corrosion and environmental cracking is substantially reduced. This is caused by the inhibiting effect of the oil film on the metal surface, which effectively reduces the corrosivity of the environment. However, the inhibiting effect is dependent on the oil phase being persistent and acting as a barrier between the metal and the corrosive environment. If GOR is not known, it is recommended that a value greater than 5000 scf/bbl or 890 m³/m³(in SI units) be used.

Water to Gas Ratio

To have corrosion in oil and gas systems, aqueous water is required. In many production applications where essentially dry hydrocarbons are being produced, the full corrosivity of the hydrogen sulfide and/or carbon dioxide will not be present.

In such systems, a dry gas is considered as that which contains no more than 2 BBL water/MSCF gas (or 11.3m3/Million m3). For Water to Gas Ratio with less than or equal to this amount, the corrosive severity is substantially reduced.

Care should be taken to evaluate presence of possible locations where water can separate from the hydrocarbons and form a continuous water phase. Under such conditions, substantial corrosion can exist.

Dew Point

In gas dominated systems, there are two measures to evaluate availability of the aqueous medium. If the operating temperature is higher than the dew point of the environment, no condensation is going to be possible and will lead to highly reduced corrosion rates. Corrosion under condensing conditions (i.e., operating temperature less than the dew point) is a function of the rate of condensation and transport of corrosion products from the metal surface. If the total water in a condensing system as measured by the Water to Gas Ratio is less than 11.3m³/Mm³ (2 BBL water/MSCF gas), corrosivity is substantially reduced. Hence the dew point plays a critical role in gas-dominated systems in that at higher operating temperatures (greater than the dew point) significantly lower or no corrosion may be observed due to absence of condensed moisture.

Water Cut

The Predict model classifies systems as oil dominated or gas dominated on the basis of the gas/oil ratio (GOR) of the production environment. If the environment has a GOR < 890 m³/m³ (5000 scf/bbl in English units)³⁵, the tendency for corrosion and environmental cracking is often substantially reduced. This is caused by the possible inhibiting effect of the oil film on the metal surface, which effectively reduces the corrosivity of the environment. However, the inhibiting effect is a function of the type of oil phase and the water cut of the environment. The persistence of the oil phase is a strong factor in providing protection, even in systems with high water cuts. In oil systems with a persistent oil phase and up to 45 percent water cut, corrosion is fully suppressed, irrespective of the type of hydro-carbon. Relative wettability of the oil phase versus the water phase also has a significant effect on corrosion. Metal surfaces that are water wet show significantly higher corrosion rates.

The degree of protection provided by oil films can be quantified only as a function of water cut and velocity. Figure 10 [36] shows data that relates the acid number of the crude to oil wettability and Figure 11 [36] shows corrosion rate as a function of produced water content for different crude oil/produced water mixtures. In oil systems the water cut acts in synergy with the oil phase to determine the level of protection from the hydrocarbon phase. However, at very low water cuts (less than 5 percent), corrosive severity of the environment is lessened due to the absence of an adequate aqueous medium required to promote the corrosion reaction.

Oil Type

The Predict model classifies systems as oil dominated or gas dominated on the basis of the gas/oil ratio (GOR) of the production environment. If the environment has a GOR < 890 m³/m³ (5000 scf/bbl in English units), the tendency for corrosion and environmental cracking is often substantially reduced. This is caused by the possible inhibiting effect of the oil film on the metal surface, which effectively reduces the corrosivity of the environment. However, the inhibiting effect is dependent on the oil phase being persistent and acting as a barrier between the metal and the corrosive environment. The persistence of the oil phase is a strong factor in providing protection, even in systems with high water cuts. In oil systems with a persistent oil phase and up to 45 percent water cut, corrosion is fully suppressed, irrespective of the type of hydro-carbon. Relative wettability of the oil phase versus the water phase has a significant effect on corrosion. Metal surfaces that are oil wet show significantly lower corrosion rates³⁷.

The Predict system provides for a significant reduction in the corrosion rate (up to a factor of 4) based on the type of oil phase being

• Highly persistent,
• mildly persistent
• not persistent.

However, the degree of protection can be quantified only as a function of water cut and velocity. The persistence determination is a more complex task and requires knowledge of the kerogen type and hydrocarbon density. It is important to understand the type of crude oil in terms of the organic compounds that make up the crude to determine wettability effects. Figure 10 [36] shows data that relates the acid number of the crude to oil wettability and Figure 11[36] shows corrosion rate as a function of produced water content for different crude oil/produced water mixtures. While the effect of persistence of the oil medium is significant on corrosion rates, it is even more difficult to quantify precise compositional elements of an oil medium that contribute to wettability and persistent oil film formation. Such quantification is possible by rigorous laboratory testing of different actual, uncontaminated (read deaerated) production water samples, so as to determine the extent of protection.

In oil systems the water cut acts in synergy with the oil phase to determine the level of protection from the hydrocarbon phase. However, at very low water cuts (less than 5 percent), corrosive severity of the environment is lessened due to the absence of an adequate aqueous medium required to promote the corrosion reaction.

Oxygen

Presence of oxygen significantly alters the corrosivity of the environment in production systems. Oldfield [39] has chronicled how presence of oxygen can significantly increase corrosion rates due to acceleration of anodic oxidation. While corrosion rate increases with oxygen, rate of oxygen reduction as a cathodic reaction is further exacerbated by:

1. Increase in operating temperature

2. Increased fluid flow leading to increased mass flow of oxygen to the metal surface

3. Increasing oxygen concentration

Data showing increases in corrosion rate as a function of oxygen concentration for differing temperatures is shown in Figure 12. Corrosion rates for different flow velocities and oxygen levels as a function of temperature is shown in Figure 13.

Sulfur

In systems containing high levels of H₂S, elemental sulfur is often found to be present. Its presence can significantly increase the corrosivity of the production environment with respect to weight loss corrosion and localized corrosion. Presence of sulfur is similar to that of having oxygen in production systems in that it can be a strong oxidizing agent and can lead to significantly increased local attack. Sulfur can directly combine with Iron to form FeS and can lead to significant metal loss in a localized mode.

Fluid Velocity

Next to the corrosive species that instigate corrosion, velocity is probably the most significant parameter in determining corrosivity of production systems. Fluid flow velocities affect both the composition and extent of corrosion product films. Typically, high velocities (> 4 m/s for non-inhibited systems) in the production stream leads to mechanical removal of corrosion films and the ensuing exposure of the fresh metal surface to the corrosive medium leads to significantly higher corrosion rates. Corrosion rate as a function of flow velocity and temperature is shown in Figure 8[15].

In multiphase (i.e. gas, water, liquid hydrocarbon) production, the flow rate influences the corrosion rate of steel in two ways. First, it determines the flow behavior and flow regime. In general terms, this is manifested as static conditions (i.e. little or no flow) at low velocities, stratified flow at intermediate conditions and turbulent flow at higher flow rates. One measure which can be used to define the flow conditions is the superficial gas velocity. In liquid (oil / water) systems, this is replaced with the liquid velocity.

Velocities less than 1 m/s are considered static. Under these conditions corrosion rates can be higher than those observed under moderately flowing conditions. This occurs because under static conditions, there is no natural turbulence to assist the mixing and dispersion of protective liquid hydrocarbons or inhibitor species in the aqueous phase. Additionally, corrosion products and other deposits can settle out of the liquid phase to promote crevice attack and underdeposit corrosion.

Between 1 and 3 m/sec, stratified conditions generally still exist. However, the increased flow promotes a sweeping away of some deposits and increasing agitation and mixing. At 5 m/sec, corrosion rates in non-inhibited applications start to increase rapidly with increasing velocity.³¹ Data shown in Figure 9[31] demonstrates the effects of velocity on corrosion rate for both inhibited and non-inhibited systems. For inhibited applications, corrosion rates of steel increase only slightly between 3 to 10 m/sec, resulting from mixing of the hydrocarbon and aqueous phases. Above about 10 m/sec, corrosion rates in inhibited systems start to increase due to the removal of protective surface films by the high velocity flow.

Flow related effects on corrosivity have been linked to the wall shear stress developed and is an area of intense research in the community. Flow induced corrosion is a direct consequence of mass and momentum transfer effects in a dynamic flow system where the interplay of inertial and viscous forces is responsible for accelerating or decelerating metal loss at the fluid/metal interface. While flow-induced corrosion is a significant component of predictive modeling discussed herein, the topic of flow-related effects is being actively researched by the authors and forms the focus of another publication. Another relevant aspect of flow or velocity induced corrosion is erosion corrosion and refers to the mechanical removal of corrosion product films through momentum effects or through impingement and abrasion. Guidelines for velocity limits with respect to erosional considerations are given in API-14E in terms of the density of the fluid medium.

Corrosion Allowance

In designing systems from materials such as steel which can exhibit corrosion, it is common to take into account and added factor of safety in terms of the Corrosion Allowance. The concept of Corrosion Allowance involves the use of an increased thickness over that required for mechanical design to allow for corrosion and metal loss that may take place during

• the project life or
• until replacement.

The magnitude of the Corrosion Allowance is dependent on the severity of corrosion expected and the ability to mitigate corrosion usually by the use of corrosion inhibitors. The Corrosion Allowance in most cases is < 0.12 inches (3 mm). However, in some particularly severe cases larger Corrosion Allowances can be utilized.

Service Life

The Service Life is the period of useful service for a particular component. This is usually taken to be the time required to achieve a corrosion metal loss equal to the Corrosion Allowance. Alternatively, the Service Life may be used to define the required Corrosion Allowance based on the assessment of corrosion severity and inhibition performance and methods in the particular application.

Type of Flow

The flow conditions (i.e. static, stratified, turbulent, etc.) are dependent on the nature of the produced gases and fluids and if the flow is primarily horizontal (surface production) or vertical (subsurface production). Horizontal flow is usually more prone to static and stratified conditions which limits the amount of mixing of oil and water phases at low flow rates. Vertical flow typically exhibits these types of conditions only during period of shut-in of the well. See fluid velocity for more information.

Method of Inhibition

For horizontal flow systems the following types of inhibition method are commonly used:

No Treatment - The conditions may be essentially non-corrosive. This usually occurs under the following conditions (a) very low acid gas (CO2 and H2S) partial pressures, (b) low amounts of water or (c) very persistent oil phase.

Continuous Inhibition - Inhibitor is continuously injected into the flow stream. This may be conducted in both downhole and surface production systems. It is preferred where the flow velocity is greater than 10 ft/sec (3 meter/sec) or where the amount of water is high.

Batch Inhibition - Inhibitor is added in the flow system periodically in batch treatments usually between two pigs. A strongly persistent filming inhibitor is usually used which can reduced corrosion rates effectively during the period between batch treatments. This technique is usually effective where the chloride concentration is high but the velocity is low. It is commonly used to supplement other inhibition techniques.

Pigging - Pigging is the use of flowline pigs to assist in (a) application of batch inhibitors and (b) removal of accumulated water, solids and other deposit in the flow system. In many applications, pigging is required to get proper distribution of inhibition chemicals through the flow system. In cases where flow velocity is low, pigging is used to remove water and deposits from the bottom of the pipe which can promote corrosion at this location.

For vertical flow systems the following types of inhibition method are commonly used:

No Treatment - The conditions may be essentially non-corrosive. This usually occurs under the following conditions (a) very low acid gas (CO2 and H2S) partial pressures, (b) low amounts of water or (c) very persistent oil phase.

Batch Inhibition - Inhibitor is added in the flow system periodically in batch treatments and usually added to the tubing bore in a process where the fluids in the well bore are displaced with the inhibitor and its carrier. A strongly persistent filming inhibitor is usually used which can reduce corrosion rates effectively during the period between batch treatments. This technique is usually effective where the chloride concentration is high but the velocity is low. However, conditions of high temperature (>250 F; 120 C) and high flow rate generally limit the use of this technique.

Squeeze Treatment - Squeeze treatments are a modification of batch inhibition used for controlling downhole corrosion. Instead of just displacing the tubing with inhibitor and its carrier fluid, the squeeze treatments also forces the fluid under pressure into the surrounding formation. This has the benefit of extending the duration between batch treatments in some wells. However, in other cases, squeeze treatments can also interfere with the well's production by plugging the formation.

Continuous Inhibition - Inhibitor is continuously injected into the tubing at bottom of the string or through a subsurface injection valve. The rate of injection is regulated to provide the inhibitor at a required concentration to mitigate corrosion. While more costly and requiring more equipment than batch inhibition, continuous inhibition has been shown to be more effective particularly in deeper high temperature wells and at more severely corrosive conditions. At high flow rates, continuous inhibitor injection may become costly and possibly ineffective.

Inhibition Efficiency

Appropriate inhibition is a critical criterion for effective use of carbon steels in corrosive production systems. Inhibition has been typically found to be viable in flows with velocity in the range 0.3 - 10 m/s. Inhibition Efficiency (IE) describes the efficacy of an inhibitor treatment in mitigating weight loss corrosion and is an important factor in assessing corrosivity. It is based on either laboratory or field data where inhibited and non-inhibited corrosion rates are compared using the following equation:

IE = 100[(CR_n - CR_i)/CR_n]

where

CR_n = non-inhibited corrosion rate,

CR_i = inhibited corrosion rate.

Values of IE near 1.0 represent conditions with maximum efficacy of the inhibitor reatment. Conditions which affect IE include:

1. Inhibitor concentration.
2. Severity of corrosive environment.
3. Service temperature.
4. Solubility of inhibitor in aqueous phase.
5. Phase behavior of inhibitor and carrier fluid in service environment.
6. Persistence of inhibitor on metal surface.

The predictive model evaluates inhibition efficacy on the basis of velocity, hydrocarbons to water ratio and dissolved chloride levels. The method of delivery (batch, continuous, pigging etc.) is also an important factor in determining appropriateness of inhibition for a given set of operating conditions.