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Guidelines for Corrosion Inhibitor Selection for Oil and Gas Production

Part 1: Corrosion Inhibition Management

J. SONKE and W.D. GRIMES,

Shell Global Solutions International B.V., Amsterdam, The Netherlands

Hans.Sonke@Shell.com and William.Grimes@Shell.com

Abstract

The application of effective Corrosion Inhibition (CI) in Oil and Gas production is essential to enable

long-term use of Carbon Steel (CS) in corrosive systems. CS as a low cost material requires proper

validation of CI effectiveness to assure operational integrity. CIs change in the face of the challenges

of field maturation, new recovery approaches, regulations, and new field exposures (e.g. higher H2S

content). These needs have also spurred development of new test protocols. Further, to address

higher integrity expectations, it has become essential to assure that field applied CI maintains

effectiveness within its Integrity Operating Window (CI-IOW).

A range of CI test methods have evolved - some useful and others less so. A lack of understanding of

corrosion fundamentals can introduce fatal pitfalls into both test design and protocols. No standards

exist that define the need for a CI testing program, yet proper qualification may require test points at

both the boundaries and within the IOW.

Based on a combination of operational experience and in-house CI testing, methods have been

developed for CI testing program identification to ensure effective CI deployment in its IOW. The

combined understanding of corrosion processes, Oil and Gas operations, and laboratory test methods

have proven to be crucial for effective CI assessment and deployment.

This paper provides guidance for CI test program definition and management to ensure and improve

the integrity of CS applications in our Industry.

Key words: Corrosion Inhibition, Corrosion Inhibition testing, Oil and gas corrosion, CO2 corrosion,

H2S corrosion, corrosion management, Integrity Operating Window.

Introduction

The base case for material selection in Oil and Gas production is the use of Carbon Steel (CS), even

in aggressive internal corrosive production environments. This use implies, for assurance of field

equipment integrity, that all relevant corrosion management issues associated with the use of CS are

adequately addressed [1,2]. Corrosion inhibition (CI), both continuously and batch applied, is one of

the common methods used to control internal (process) corrosion of CS in oil and gas production,

transportation and processing facilities. A large number of commercial CIs are available, and new

products are continuously introduced to handle new and more corrosive conditions and meet ever

more stringent regulations. This document is intended to provide guidance on definition of the

critical operational conditions and the use of that definition to define the scope of work for effective

selection and application of CI products.

To manage the risks associated with corrosion it is necessary to define and document the exposure

Integrity Operating Window (IOW) [3,4] for the materials and, as applicable, the mitigations, to

manage processes within its identified limits (or envelope). This approach also applies to the

application and qualification of CI products, based on the observed limitations of these chemicals.

IOWs thus need to be defined for specific CI products, the “CI-IOW”, to validate the CI’s suitability

for the field IOW. To perform this validation, first define the required field IOW, from which it is

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possible to define test requirements (the test program) for the CI and its associated implementation,

operation, and surveillance needs. Management of Change (MOC) is required to address excursions

from the specific CI-IOW, which may be either field exposure changes or implementation

requirements from new projects or regulations.

The Scope of this paper is identified as “Selection of both continuous and batch corrosion inhibitors

for Oil and Gas production”. The basic limits of the scope are defined as upstream processes,

including wells, flowlines, pipelines, and process equipment. The methods outlined in this paper are

limited to mitigation of internal production water corrosion and, within limits, of “condensing

water” corrosion. The specific methods identified herein are generally for temperatures ranging up to

120 °C and pressures up to 200 barg, although the methodology is applicable beyond this range.

Systems in which corrosion control by chemicals other than corrosion inhibitors, (e.g., for microbial

corrosion, oxygen corrosion), are also beyond the scope of this work, although again, a similar

methodology should apply.

Corrosion Inhibition Management

To be able to have a successful CI application all relevant management processes need to be

addressed: – scope of the application to be validated, the validation approach, the validation itself,

communication of the scope to operations, and deployment of required operational activities and

surveillance [5-8]. This suggested Corrosion Inhibition Management process is outlined in figure 1:

Corrosion Inhibition Management Process

1. Document Production Dataa) Equipmentb) Chemicalsc) Process Datad) Compositions (gas, oil, water,

S0, solids)

3. Select CI and 4. Assure CI

performance (lab/field)

1.1 Identify Operating rangea) Process Assessmentb) Corrosion Analysis

1.2. Define Integrity operating Window (IOW)

2. Define Corrosion Inhibition (CI) test program

Fail PassAdjust:Dose rate, chemicals, IOW, …

Review / acceptanceBy Principal

4.1 Report results (IOW)

5 Implement Operate and Maintain Including:a) Process surveillanceb) Corrosion Managementc) Chemical Management

Yes

5.3. MOC

5.1 WithinIOW and

Integrity OK?

1. Identify Application Windowa) Process data (P,V,T, flow, etc.)b) Compositions (gas, oil, water, solidsc) Equipment (line, material(welds), etc.)d) Chemicals e) Operations 5.2

Correctable in IOW?

Correct issue.

Yes

No

No

Figure 1. Corrosion Inhibition Management Process.

The Corrosion Inhibition Management Process follows the following major steps:

1. Identify the needed Application Window by collecting, “harvesting”, the required field data

1.1. Assess the resultant operating range(s) by filtering the data and the needed CI performance

by a corrosion analysis

1.2. Define the final Integrity Operating Window, including corrosion mitigation measures

2. Define the program for CI test validation, fully addressing the field’s CI-IOW envelope for all

needed mitigation measures.

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3. Select (candidate) CI products based upon the required CI-IOW validation requirements, based

on relevant prior field experience, test work, and available expertise.

4. Assure the CI performance for the required CI-IOW, by reviews of prior tests, performance of

new tests, or field work.

4.1. Document the (proven) CI-IOW to field Operations staff, including process limitations and

associated corrosion and chemical implementation and surveillance needs

5. Implement use of CI in the field, in accordance with documented requirements and IOW.

Perform surveillance to assure use is within the identified CI-IOW envelope and requirements

5.1. Routinely validate operation within the CI-IOW and that needed integrity is achieved.

5.2. Perform corrections and validate success, as needed. If unsuccessful, then...

5.3. Raise an MOC and address deficiencies.

These steps are further described in the following sections.

1 Application window

Identification of the application window involves data gathering (and estimating), data filtering to an

essential window based upon corrosion and CI impact, and corrosion analysis to further define

testing needs within this window. Initial steps to identify an application window (1) are to identify:

Scope(s) of interest (e.g. well, flow line, process facilities, pipeline) including design

requirements, e.g., corrosion allowance, materials (including welds),

Estimated period of interest, a few years or asset life, to identify expected changes in the field

exposures. (These items are listed in section 1.2, after further definition of table content.)

For identification of the operating range (1.1), field data that will have a specific impact on both

corrosion and corrosion mitigation efforts (CI effectiveness) needs to be gathered. Data to be

gathered includes process data, compositions of gas and liquids, other treatment chemicals, and field

operating capabilities, as they may impact corrosion or CI performance. The aim of the process

evaluation is to define the IOW needed for the CI application.

Production changes that can be expected within the period of application need to be incorporated in

the data assessment, e.g., water breakthrough and its impact on salinity(TDS), sand production,

pressure, temperature, velocity, fluid composition (e.g. new wells). Based on the gathered data an

analysis shall be made that defines the CI-IOW.

1.1a Process Assessment

The goal for the process assessment is two-fold. First, the process data needs to be assessed and

filtered for the values or ranges that will be applicable to the candidate field application. Second, the

process assessment will identify data used in the CI qualification and corresponding field

surveillance. For each parameter there will be a required assessment value or range that will result

from the process assessment.

The purpose of identifying the operating range is to filter, often complex and wide ranging data sets,

gathered from the prior “harvest”, down to essential ranges for corrosion and CI evaluation,

specifically as these operating conditions impact the corrosion rate and corrosion inhibitor

effectiveness. For example the %CO2 and pressure data would be combined to identify the

maximum partial pressure of CO2 in the field. Flow is another important parameter, with either low

flow (risk on water dropout / solid deposition) or high flow (shear>25 Pa) potentially having a strong

impact upon both corrosion and inhibitor performance. In a few cases, the end qualification ranges

identified, may result in qualification of more than one inhibitor, but more often the end result is

identification of a single product that satisfies the operating range requirements.

Some data is mandatory to define the CI-IOW. Data may be unavailable or poorly defined, but,

when data is lacking, experts should be able to identify an acceptable estimate for relevant critical

parameters. For example:

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For a new field, %CO2 may not be identified. However, internal corrosion is proportional to

the log of the CO2 partial pressure, and an estimate, ±25% or a p90 is often be used as an

estimate.

Flow may not be known. However, for a pipeline only limited pressure drop is acceptable,

per design, and shear estimates based upon pipeline design criteria are quite acceptable.

In situ pH may not be exactly known, but back-calculated estimates from field pH

measurements with alkalinity or organic acids can provide sufficient data.

1.1b Corrosion Analysis

The purpose of the corrosion analysis is two-fold. First the corrosion threats need to be assessed by

determining the maximum unmitigated corrosion rate and type(s) of corrosion present. The second

purpose is to define any special challenges relevant to corrosion inhibition performance (e.g. high

wall shear stress, CI-Chemical performance compatibility) as well as specific requirements needed

for corrosion management [7,10] (e.g. injection availability, scraping {cleaning pigging}).

A corrosion analysis for upstream processes should include corrosion modelling to define the

maximum unmitigated corrosion rate, identify the corrosion mechanism and estimation of the

required availability for CI injection.

Defining the dominant corrosion system as sweet, sour or a mixed regime [12,13] is one of the first

actions of the corrosion analysis.. It is acknowledged that the criteria to determine the dominant

corrosion regime are not fully defined [14]; therefore, the limits mentioned herein are historical and

nominally those most commonly used (and subject to future refinement). The dominant corrosion

regime has a significant impact on both the corrosion rate model and the needed equipment and

operational practice for corrosion management and mitigation:

Sweet corrosion (e.g., CO2/H2S ratio > 500): CO2 and organic acid corrosion are widely

studied [12-34] and models have been developed to assess the associated corrosion rate [12-

20]. This type of corrosion threat is mainly uniform and dominated by acid gas, water

chemistry, temperature, and flow conditions. The mostly uniform corrosion rates may be far

oven 10 mm/y. When rates are very high proper implementation of CI operations becomes

more important, and CI availability, persistency, and dosage become more critical. The

mostly uniform CO2 corrosion attack may exhibit local attack when CI mitigation operations

are deficient, and evaluation of localized attack is critical to the CI performance assessment.

Corrosion monitoring and inspection can follow an RBI approach where local performance

and surveillance should reflect conditions over a larger area.

Mixed regime (e.g., CO2/H2S ratio 20 - 500): The corrosion processes dominating this regime

are influenced by the presence of H2S; however, the corrosion is found to be akin to those of

the sweet corrosion regime [19]. It has been observed that the presence of even small

amounts of H2S reduces the corrosion rate below that seen in the sweet corrosion regime, due

to the co-precipitation of FeCO3 and non-continuous FexSy scales [33,35,36]. Since this

dominant corrosion mechanism is comparable to sweet corrosion, the corrosion mitigation

requirements for sweet conditions can be applied.

Sour corrosion (CO2/H2S ratio < 20): Applied in the context of carbon steel corrosion

(differing from the risk of sour cracking), sour corrosion is where H2S and continuous,

conductive FexSy scales dominate the corrosion mechanism [37-47]. Sour corrosion is

dominated by the immediate formation of protective, continuous, semi-conductive iron

sulphide (FexSy) scales. These scales can be locally disrupted causing highly localised/pitting

corrosion driven by the galvanic processes. This localised corrosion is strongly enhanced by

the presence of deposits (sand, FeS or elemental sulphur), higher salt content (specifically

chlorides), and a minimum flow leading to under deposit corrosion [7,10,37,38]. The

presence of glycol/alcohol [37-46] can fully disrupt the scale formation kinetics and heavily

mitigate formation of protective scales on the metal surface. Impact of increased temperatures

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can enhance the scale protectiveness [47], further reducing the unmitigated corrosion rate.

The sour corrosion threat is mainly one of localised attack and corrosion mitigation often

requires batch inhibition and deposit control (scraping/pigging) in addition to continuous CI

injection [7,10]. Corrosion monitoring and inspection cannot follow an RBI approach as

detection of local corrosion is critical and much higher inspection area coverage is required.

The presence of elemental sulphur can have a significant impact on sour corrosion, and

involves an additional corrosion mechanism(s) [42]. Sulphur presence may occur due to

oxygen ingress, direct precipitation from the gas phase onto the metal surface, or downstream

drop-out of entrained sulphur solids. Sulphur presence can functionally be considered an

undesired upset to be controlled by avoidance of O2 ingress, the use of sulphur solvents, and

deposit control (scraping).

Definition of the type of corrosion threat allows both identification of effective corrosion mitigation

needs and appropriate surveillance. This will differ considerably for sweet (and mixed) versus sour

corrosion conditions.

1.2 Define a Corrosion Inhibition - Integrity Operating Window (CI-IOW)

An IOW in the context of a CI is defined as those operating conditions that have a critical impact

upon the success of the CIs performance. The CI-IOW needs to cover the full range of operating

conditions that impact the corrosion rate and corrosion inhibitor effectiveness [5-9,48-68]. A CI

qualified for an IOW implies that if conditions exceed the defined window then CI performance

cannot be assured and CI re-evaluation is required. A CI-IOW may not have to cover a whole

process system/field or the complete expected production life, but its application should be within

the identified CI-IOW, with surveillance present to verify such operation.

A CI-IOW will include Base Case parameters mandatory for any CI-IOW, Boundary parameters

which are applicable as present, and Application properties specific to the field design needs. (See

Table 1 for Base Case and Boundary parameters, which are also outlined in section 2.)

The Base Case parameters to define a CI-IOW are those most strongly, impacting corrosion and CI

performance. These are defined as the process conditions of (A) Temperature, (B) Partial pressures

of acid gasses, (C) water chemistry and (D) hydrocarbon (oil) water ratio (table 1, items A-D). The

Base Case typically needs to cover a range of conditions which often requires evaluation of more

than one field exposure condition.

There are often further parameters that can significantly impact corrosion, corrosion mitigation, CI

performance and corrosion management which should be included in the CI-IOW. These Boundary

parameters are included in the CI validation and define the limits in the CI-IOW, identified in Table

1 as items e-l. This may also include specific mitigation requirements including the selected

inhibition approach and mitigation control criticality, e.g., CI injection availability, batch inhibition

frequency, scraping frequency for sour corrosion [7,10].

Finally, to ensure effective chemical function, CI Application performance properties, (attributes),

are critical to the successful physical deployment of the CI chemical, [6-9,52,54]. Metallic and non-

metallic material compatibility with the CI, both within the injection system and in the process flow,

need to be identified, assessed, and addressed. Other examples are maximum viscosity, thermal

degradation, shelf life stability at field storage temperatures, and chemical reactivity and co-solvency

with used chemicals. Note that these basic Application properties are considered to be common to

the selection of most any treatment chemical, and as such are not addressed in this paper which

focuses upon CI performance verification. These attributes are the subject of other documentation

[69].

Based on the defined CI-IOW a test program can be constructed that validates the performance of the

CI under the identified conditions. This CI-IOW can thus be created and communicated that defines

required surveillance and operational needs for process, corrosion, and chemical management.

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Table 1. Overview of items to be included in the definition of the CI-IOW.

2 Identification of the required CI qualification assessment (test/validation program)

Based on the identified CI-IOW a test protocol can be formulated, suitable for the specific

application. There are two test program approaches to validate the CI performance within its IOW.

In one approach, a test program is developed that covers all possible combinations of the critical

exposure conditions – all temperatures, salinities, oil/water ratios, treatment chemicals, flows, etc. A

more efficient approach is to identify a few critical, severe, Base Case exposures, then validate the

full CI-IOW performance at appropriate extended Boundary excursions from these base conditions.

Base case exposure conditions, critical for CI performance evaluation, are the temperature at highest

corrosion rate, the highest exposure temperature, and, the highest salinity/total dissolved solids

(TDS).

Based on the identified Base Case conditions a test program can be designed to address these

exposures and excursions from these conditions. Base Case CI performance validation (e.g.

parameters A-D) is often performed in a standard autoclave test. To validate the boundaries of the

full applicable CI-IOW (e.g., previous items e-l) other tests should be added to the program to cover

further parameters that can impact the CI performance in the CI-IOW. The final test program should

reflect the entire range of expected exposure conditions [5-8,48-68]. In principle the full window,

including “boundary” exposures, should be tested/validated as extensions of all critical Base Case

conditions as a matrix of required tests. For identification of a critical window of conditions for

testing the following criteria are recommended:

A. The maximum partial pressure of acid gasses, pCO2 / pH2S respectively, should generally

be used for the test exposure. The applied pressure may be derived directly from the partial

pressures present in the process, but at high pressures (> 150 barg) the fugacity may be

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taken into account. The partial pressure tested may be lower to represent lower temperature

conditions found along the pipeline pressure-temperature profile, noting that the near

coolest exposure may not be at the end of the pipe pressure. For liquid full systems the

selected pCO2/pH2S should take into account the fugacity pressure for the liquid. To avoid

depletion of corrodents a continuous purge of acidic gasses is recommended during testing,

especially for long term or low pH2S or pCO2 tests. An exception may exist if the mixed

corrosion system is present, as in this case more H2S reduces corrosion. Thus, in mixed

corrosion systems, less H2S, a representative minimum, is preferred for testing, but to

compensate for the lower net acid gas, pCO2 may be equal to pCO2 max.+ pH2Smax.

B. For temperature it is critical to look at both the full range of exposure temperatures and,

potentially, intermediate temperature(s) at which the maximum unmitigated corrosion rate

within this range would occur, as shown on Figure 2. This temperature range can be quite

different for flow lines that may see hot fluids directly from a well versus pipelines which

more-often see conditions from cooler comingled streams. CIs more often perform poorly

at the temperatures of maximum unmitigated corrosion and highest temperature, but

performance at the lowest temperature should also be verified, as suggested by the “X”’s on

Figure 2. Determination of the corrosion profile versus temperature may be performed

using either calibrated corrosion models or by corrosion testing.

Figure 2 Typical Sweet and Sour corrosion behaviour versus temperature, plus example

minimum test temperature conditions (“X”) for a pipeline.

C. Water compositions, Prior to acid gas saturation, the test water chemistry should reflect

that measured from actual, depressurized field samples(if available) and include similar

salinity / total dissolved solids (TDS), organic acids concentration, and pH. Iron should be

included when modelling corrosion versus temperature, but iron (Fe) is normally not be

added to the test water to mitigate iron oversaturation and scale formation. Beyond

available field analysis, future changes need consideration, e.g., water breakthrough can

change conditions drastically from condensing water with limited salinity (low TDS) to

reservoir waters that are normally more highly saturated with dissolved solids (high TDS).

Since Calcium (Ca) has a strong tendency to cause scaling this may be replaced by sodium

(Na) while keeping the TDS at the same total molar level. If dissolved sulphur is naturally

present in the aqueous phase, this should also be added.

Temperature

Corr

osio

n ra

te

Typical behavior Sweet

Typical behavior Sour

Application pipelines

X = suggested condition for CI testing

X

X

X

X

X

Application flowlines Application wells

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While the corrosion rate is typically highest at high temperature and low TDS, the CI

performance can be strongly impacted by low temperature and high salinity, a potential

base case condition if high TDS is present. Sour pitting corrosion rates are also strongly

impacted by TDS.

D. Oil/Condensate composition and water ratio range can impact CI performance due to

presence of natural surfactants in the oil (promoting emulsions), natural inhibitors in the oil,

and partitioning between the oil and aqueous phase [54]. Hydrocarbons can themselves

contribute to the CI performance [55] and the presence of hydrocarbons may be crucial to

the performance of some CI products.

Water/Hydrocarbon Ratio has several effects. Low water cut reduces the corrosion rate by

promoting hydrocarbon wetting of the steel. Some inhibitor types, e.g., oil soluble/water

dispersible, may also require minimum flow turbulence to effectively partition into the

water phase.

For systems presently with a low water cut, limiting test conditions to such an exposure

simulation may give a lower corrosion rate than can occur at conditions where water drop

out occurs. As the behaviour of the CI in relation to its partitioning can have a strong effect,

a pre-partitioning step with a second autoclave in the test protocol is suggested. For the

above reasons a minimum 50% water cut is recommended in the final corrosion test cell.

Summarising the above analysis, the critical Base case test conditions should include:

Table 2 The test matrix definition of Base Case conditions for CI qualification. (See Notes)

Notes: 1. All Base Case test conditions are at representative highest TDS and highest watercut/lowest OWR

(typically minimum 50% to assure water wetting) expected conditions.

2. Depending upon exposures, as many as three or as few as one Base Case test conditions will be present.

The identified Base Case conditions should be the basis for the test program design. In addition to

base case testing, testing at Boundary conditions needs to be added to address the full CI-IOW.

These are, as applicable: (1) at representative low TDS conditions, (2) at low temperature, and (3)

partitioning tests at representative low water cuts. Normally the base case and extended boundary

condition testing can be executed in a standard autoclave test. Finally, more specialized Boundary

tests may need to be added, as executed at the Base Case conditions present, as presented in Table 2

and as detailed in the following paragraphs.

Other “Boundary” parameters that can significantly impact CI performance and whose assessment

may need to be included in the CI-IOW and test program are:

e. The use of a Batch Inhibitors (BI) can address pipeline top of line corrosion, address end-of

line corrosion mitigation when scraping removes CI treated liquids in line slumps, restore

corrosion mitigation after a mechanical upset (e.g., scraping, well workover), provide for

long periods of shut down, or be used as a treatment program by itself. BIs are especially

relevant for sour conditions where scraping is often integral to good corrosion management

[7,10] . In these cases the use of the BI and the scraping frequency should be included in the

corrosion inhibition strategy and become part of the validated CI-IOW. Batch inhibitor

treatment programs rely on the CI persistency which determines the batch treatment

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frequency. Even continuously treated sweet wet gas pipelines may need batch treatment, as

after scraping operations to remove water in line slumps, those same slumps will prevent

injected CI from reaching condensed water accumulations further down the line until the

sumps reach a stable liquid hold-up fill. [71]

Table 3 A test matrix for CI qualification defined around the Base Case, and including

Boundary exposures to fully cover the CI-IOW limits (2 examples X and Z, See Notes)

Notes: 1. The process is to first identify and mark base case conditions present. Then, for each base case condition

present, add further tests to address the full IOW depending upon expected field conditions. Some “Base

Case” conditions should require further boundary tests (See following notes). Examples are shown.

a) Typical sour gas flowline at normal flow rates, low TDS, single OWR, where batch treatment is planned to

address FeS deposits (X).

b) Typical sweet wet oil pipeline, no chemicals, normal flow, and low TDS, but with welds >0.5%Ni (Z)

f. To assure full IOW coverage is provided, further tests, beyond the base case conditions,

may still be required, i.e., low temperature, low TDS, and highest OWR (discussed next).

These assessments should be conducted as logical extensions of the appropriate Base Case

conditions. Note that in some cases other Base Case test parameters may change, e.g., the

temperature of maximum corrosion rate may be different for a high and low TDS system,

and these other parameters should be modified as needed to provide full IOW coverage.

g. Partitioning of CI between a hydrocarbon and aqueous phase can impact the available CI

presence at the wet metal substrate. CI partitioning can be significantly impacted by process

conditions [5,6,8,54,64,67,68], such as mixing energy at the injection point and turbulent

versus stratified flow. Replicating the partitioning behaviour in the lab can be crucial for CI

deployment success.

Partitioning is often expressed as a partitioning coefficient (Kpart) that is the ratio of CI

concentration in the liquid hydrocarbon phase (coil) vs the water phase (cwater):

water

oilpart

c

cK

Determination of this partitioning coefficient can be a challenge. CI products are usually a

blend of a number of chemicals, whose individual partitioning behaviours are different –

potentially so different as to accumulate in the aqueous phase differently depending upon

specific lab or field process conditions encountered [8]. This may result in CI performance

that is different at different oil-water cuts, despite an apparently sufficient aqueous dosage

basis a CI residual measurement (usually based on only one or a few components).

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CI products may be labelled “water soluble” or “oil soluble/water dispersible” but actual

behaviour is less sharply defined. Field process conditions such as mixing energy at

injection points and flow turbulence can impact actual physical presence of CI in the

aqueous phase, especially for water dispersible chemistries. While a technical definition of

partitioning may not include fine CI droplets dispersed in the aqueous phase, it is both

realistic and practical to include such in CI partitioning analyses – but such analyses then

become dependent upon the mixing energy applied to the oil-water mixture. For more oil

soluble CI products CI validation requires controlled mixing which should closely match

with the field application.

In addition to water/hydrocarbon blend effects and flow/mixing impacts, partitioning can

depend on pH, salinity and temperature [68], and as such these factors should be included in

the CI-IOW and matched in CI tests, including in the pre-partitioning steps.

In the event of pre-partitioning for a low water cut condition, selective extraction and testing

of water drop out liquids is essential to avoid false positive results. With a reliable residuals

procedure in place, partition coefficients can be generated as a function of field brine

composition, water cut, temperature, and the CO2 partial pressure. For CI testing a pre-

partitioning step (in a preparation vessel) can improve the CI assessment, especially for

cases of high OWR, and such an approach is normally recommended. “Base Case” testing

should be performed representing the nominal highest expected water cut and, to address

the non-uniform partitioning of CI blends, an extended boundary test should also be

performed at the lowest expected water-cut (highest OWR) where water drop-out is

expected.

Sulphur solvents can also impact inhibitor partitioning, with the added potential

complication of themselves acting as corrosive agents, thus impacting CI selection. Sulfur

solvent effects would be assessed in the same manner as for partitioning. If sulphur solvents

are used to avoid elemental sulphur deposits [7,10], these should also be incorporated into

the test matrix.

h. To assure Chemical compatibility, since CIs are often used in operations with other

chemicals to optimise and safeguard production, evaluation of the effectiveness of CI in the

presence of other chemicals is relevant. Other production treatment chemicals can

significantly impact CI (and each other's) performance [5,6,8,52,54,65]. As a significant

impact on the effectiveness of CI should be expected when hydrate-inhibitors, scale-

inhibitors, and foamers are present, autoclave, Base case(s), functional performance testing

in the presence of such chemicals should be performed.

A further requirement to consider is identification of compatible ratios for these chemicals if

co-injection is planned, as the chemical ratio has been observed to influence CI

performance.

i. Specific material grades, including weld metallurgy, can impact CI performance [6,8]

depending upon material type and process conditions. For severe exposure conditions,

especially in sour conditions and high temperature sweet scaling conditions, it has been

observed that the specific material type (e.g., C-Mn versus Cr-Mo steel; metallurgical

crystal type) can strongly impact the corrosion and corrosion inhibitor performance, and in

such severe exposure conditions it is recommended to use the actual pipe/tubular material.

In less severe sweet conditions it is often suitable to use a standard C-Mn steel such as A36

or X60, which also provides a useful comparison point in a database of inhibitor

performance tests. Also consider material-chemical compatibility for equipment handling

CI injection, although this is usually handled as part of the application assessment.

Experience has also shown that CI performance at welds can be very different from

performance on the parent pipe/bulk material [72-74]. Welds with an elevated nickel content

have been shown to impact CI performance resulting in severe corrosion of the Heat

Affected Zone (HAZ), weld metal, or parent material, an effect known as Preferential Weld

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Corrosion (PWC). If welds with greater than 0.6% Ni are present in production equipment

and pipe work, evaluation of the effectiveness of the CI with respect to PWC is

recommended.

j. Deposits [68,52,75] can impair CI effectiveness by just physically impairing CI access to the

metal surface, but some deposits – FexSy, and Sulphur – may also directly enhance the

corrosion. In sour conditions the presence of deposits, have a major impact upon the

unmitigated corrosion rate. Thus, for sour systems assessment of CI performance under a

FeS deposit is needed, and corrosion mitigation requires deposit control.

Summarising the impact of produced sand and solids on CI corrosion control:

i. Erosion corrosion in high velocity flow will remove protective corrosion scales,

change the substrate to bare CS, and remove protective CI films. Generally CIs do

not perform acceptably in such conditions, and the recommended approach is to

detect and avoid such high velocity exposures with solids present.

ii. Low solids production and modest suspended flow may result in depletion of CI

from the aqueous phase, as a result of adsorption on solids particles. In rare cases

where this is present, an assessment of CI depletion may be made by comparing

residuals from a fixed dosage in a stirred solution with and without a comparable

suspended solids presence, although this may be of quite marginal accuracy.

iii. Deposited solids in low flow may result in insufficient CI penetration to the pipe

wall. In systems where solids deposits may occur due to combined low flow, solids

sources, and no solids removal, testing of CI performance in the presence of deposits

should occur.

iv. For Sour conditions the impact of FeS deposits on CI performance should be

incorporated into the test matrix. The effect of elemental sulphur, as precipitated

either directly from a high % H2S gas (typically >10%) or due to oxygen ingress in

low H2S systems, requires additional measures like cleaning by scraping and the use

of sulphur solvents.

k. Flowing persistency is an indication of CI effectiveness after CI treatment ceases, either due

to stoppage of chemical injection or production flow. CI persistency is often needed to

overcome short upsets in CI injection for highly corrosive fields where high injection

availability requirements [6,8] exist and to address production shut-ins. Persistency can be

defined as the tendency for a CI to be retained on a surface and as a consequence maintain

inhibition of corrosion. Persistency tests, either in a autoclave or high shear test, should be

performed if required injection availability for corrosion mitigation is high (typ. > 99%) and

otherwise as needed for operational flexibility.

l. High flow velocity, resulting in an elevated wall shear stress (Pascal, Pa), is known to impact

the effectiveness of corrosion inhibition [6,8,51,53,54,65]. A frequently used guideline of

20m/s, which may be better defined as a wall shear stress above ~25 Pa., is often identified

as the limit above which high shear testing is needed. Increased velocity has a dual impact

by both increasing the likelihood of CI desorption, impacting CI film formation, and

stimulating diffusion processes that increase the maximum corrosion rate. Higher shear rates

can be expected in risers, at inclinations where water can drop down at the sides of the pipe,

and during slug flow, thus requiring proper flow modelling. When considering slug flow one

needs to include the expected slug flow frequency, as slug flow may be excluded for CI

validation if the frequency is low, e.g., less than once per day. Testing should preferably be

executed in a flow loop [6,8,65] or other system that provides a consistent, near constant

shear profile on the test specimen.

The impact at low flow velocity can include water drop out and deposition of sand and scale

debris. This effect is especially relevant to sour conditions where a minimum flow is part of

the mitigation of under deposit corrosion [7,10,37,38].

12

m. CI assessment to address other upset conditions/exposures and special project issues, e.g.,

O2 ingress, acid flow back after a well job, batch solvent treatments, TDS increases at valves

due to flashing conditions, solvency of inhibitor carrier into high temperature, high pressure

gas in wells, will require added assessments and may need to be included in the CI-IOW test

assessment. Such upset exposures become more relevant when they happen frequently

and/or over a longer period. However, such upsets may be either short term or even “one-

off” exposures and hence, their inclusion in the CI-IOW should be assessed on a case by

case basis. For example, after an acid treatment the acidic returns may accumulate in the

system due to e.g., relatively low stratified flow at a low point, causing extreme corrosion

over a relatively brief span of time [38,66].

Based on the defined IOW for CI a test program can be constructed that ensures the impact of the

performance of the CI under the defined IOW envelope conditions.

3 Selection of CI candidate products

Based on the defined CI-IOW and the required CI test program one or more CI products need to be

found that can meet the CI-IOW requirements. The first step in finding a suitable CI is for the user to

communicate the CI-IOW requirements to potential supplier(s). With this information at hand a

supplier should find product(s) that are suitable to cover the requirements. For selection the supplier

can use data that comes from field experience at similar conditions, previous CI test qualifications or,

using internal expertise, or develop a CI specifically to meet the needed requirements. Selection of a

candidate product based on matching experience or qualifications can be straight forward and lead to

relatively fast product selection. If a new product development is required the process can be more

time consuming and vendor testing might be needed to confirm the potential suitability of a product.

Based on the available data and its relevance for to the proposed CI application, a product’s

performance qualification /validation program can be optimized.

CI testing data for candidate product selection may be less demanding, and a relative performance

assessment, based upon limited, less rigorous tests may be performed to identify candidate products.

However, a relative performance assessment usually does not provide full and final assurance of CI

performance across the CI-IOW, and a full validation assessment, with appropriate quality controls,

is required to ensure complete CI-IOW integrity. Test data should always seek to replicate actual

field exposures in line with the defined CI-IOW.

4 CI-IOW Product Validation / Qualification

Based on the previous analyses a full assessment program can be identified and documented as the

basis for the CI verification and implementation. With the full CI-IOW envelope identified,

subsequent field and/or laboratory based final performance assessments need to provide full

coverage. To ensure data of relevant quality, these final assessments should be witnessed or

performed by the user or a user qualified and audited independent agency. This full validation

assessment should provide data that reliably indicates the performance of the CI under all the field

conditions that can be expected, as defined in its CI-IOW. Details of test protocol impacts are beyond

the scope of this paper, although we do plan to document such test protocol issues and proper

approaches in more detail for CORROSION\2017.

Field validation of CI performance may be performed to assure CI-IOW suitability, but such

assessments needs to consider the practicality of performing the assessment across the entire

identified IOW. If future operational changes are incorporated in the IOW, access to a suitable

exposure will likely be limited or, perhaps, not yet actually present in the field. Field validation also

requires accurate capture of the CI performance which may not be within the capability of existing

field monitoring tools, requiring either upgrades or a move to laboratory assessment. An assessment

program employing and potentially modifying a production side stream, e.g., the Field Corrosivity

Toolbox (FCT) [80,81], may be used to expand the field validation capabilities, if suitable field

13

fittings and utilities are present for such a testing installation. A blend of field and laboratory

approaches can also be considered.

A laboratory validation assessment needs to be performed using test methods, protocols, and

conditions that replicate the field conditions [5,6,8,48-64] as identified in the CI-IOW assessment

envelope. The program is usually initiated by testing the Base Case exposures, followed by the

balance of the test program to validate the full boundaries of the CI-IOW.

The test exposures as defined in the Base case are often performed by an autoclave (vessel) test

design with test specimens exposed to a low consistent shear. These tests facilitate proper pre-

conditioning of specimen and fluids applied at the specified CI-IOW test exposures (see figure 3)

Figure 3 Schematic representation and photo of a standard low pressure autoclave set up

This type of test can also be used for dose rate optimisation, if required, and several of the extended

boundary tests (with a modified scope/protocol).

The test usually includes electrochemical measurements e.g. use of LPR (linear Polarisation

Resistance) and/or EIS (Electrochemical Impedance Spectroscopy) to assess both sort and long term

corrosion rates. After the test the probes are evaluated using weight loss and, more importantly,

assessed for localised corrosion, as such local attack often dominates when CI performance or

dosage is marginal. Even with electrochemical measurements, sufficient test time is required to

enable identification and provide accurate quantification of localised corrosion [8].

For validation of CI performance in some of the CI-IOW boundary conditions, specific, special tests

are needed. For high shear a flow loop can be used, where a measured wall shear stress directly

relates to calculation of wall shear in field exposures. Specific test designs are also available to

evaluate PWC [6,57,72,73,74], under deposit performance [75] and BI validation [6]. Note that these

more specific tests also require specialized protocols to properly validate the performance of the CI

against its IOW limits.

To provide some guidance a summary is provided following identifying some minimum

requirements for a CI performance validation assessment:

i. Preparation of the samples for testing shall include cleaning, and, preferably, pre-corrosion by a

standardized procedure. (Pre-corrosion, at a minimum, should seek to replicate any uniform thin

scale of corrosion products normally formed in field exposures, if such films are present.

Contra-wise, if corrosion product films are not expected, e.g., in low temperature sweet

exposures, pre-corrosion should be designed to avoid such film formation.)

ii. The sequence of H2S purge, if not injected as a mixed gas, should be in consideration of the

primary corrosion mechanism.

14

iii. Sufficient time during of the validation testing shall be provided to validate localised

corrosion/pitting and cover pit initiation / propagation. (A duration of 500 hr. seems to be a

minimum effective time for validation testing, i.e., detection of 10 microns damage for a pass

criteria of 0.2 mm/yr.)

iv. Corrosion product scaling conditions shall be avoided in the test, if scaling is not expected in the

field exposure. This requirement may require refreshment of autoclave brines, depending upon

the test approach chosen. Contra-wise, if corrosion product films are expected in the field, this

should be addressed either in the protocol approach or by use of controlled pre-corrosion on test

specimens.

v. Corrosion rate validation shall be provided by weight loss and assessment of localised attack. In

situ electrochemical evaluation (e.g., LPR, EIS), should be included.

A low corrosion rate from electrochemistry does not sufficiently address localised attack –

verification by specimen analysis is needed.

EIS can provide information on CI film formation and integrity [76-79].

In addition to the above issues, captured during performance of the CI-IOW process, there are many

other elements to proper CI testing, e.g., deoxygenation, water/hydrocarbon simulation, acid gas

replenishment, that are addressed in test protocols that are beyond the scope of this paper.

5 Implementation and Surveillance of CI application

Corrosion Inhibition performance shall be identified as a field key performance indicator (KPI) as

part of the corrosion management strategy. Once a CI is selected as previously described, KPIs

should be defined as:

i. Operating within the defined IOW and in line with the CI qualification CI-IOW, as identified

in process and liquid chemistry operating conditions, e.g., pressures, temperatures, gas

composition, oil/water ratio. (See Table 1.)

ii. Appling proven CI dose rate (injection) in line with the required CI concentration based on

total liquids, including oil water partitioning. The application rates will require regular

adjustment to compensate for fluctuations in liquid production rates and ratios.

iii. Recording CI availability uptime/downtime and regularly comparing actual injection

performance against uptime and dose required by the CI design and corrosion assessment

[6,8,9,11]. Requirements for a very high availability may include: automated shut in with CI

pump failures, presence of spare pumps, remote automated adjustment, and higher inspection

and monitoring frequencies. A CI assessment that can be incorporated to reduce the estimated

corrosion impact of short CI injection downtime upsets is the validated CI persistency.

iv. Assessing and recording the total time of upsets within (or beyond) the IOW design. The

impact of such upsets should be shorter than the upset period incorporated in the design.

v. Implementing and recording special mitigations and risks relevant to the risk of under deposit

corrosion.

a. BI frequency treatment.

b. Scraping frequency

c. Velocity /flow behaviour below a water or deposit drop out limit.

d. Documenting solids production events.

These KPIs need to be evaluated and reported to accountable management on a frequent (yearly or

less) basis. Alarms and surveillance activities need to be defined that trigger adjustments in a manner

timely with respect to the un-mitigated corrosion rate. Alarms should include injection availability

and selected on-line critical CI-IOW parameters. The remaining offline measurements shall be

performed on a regular basis and actioned if the boundaries of the CI-IOW are exceeded. Trending of

relevant parameters (e.g. TDS, water cut) is recommended to project if the IOW boundary will be

breached. Table 4 provides examples of KPIs for corrosion management:

15

Table 4 CI Recommended practice: CI-IOW Surveillance triggers vs validated CI

performance and CI & Corrosion Management tracking KPIs [10].

Results of the continuous validation of process data, inspection data and monitoring data shall be

routinely reviewed as an indication of effective CI performance. Undue upsets should be investigated

and addressed as needed.

Long term changes, i.e., parameters outside the documented CI-IOW envelope, should initiate a new

CI validation. Such actions may be incorporated into the MOC process as outlined before. Changes

initiating a new CI-IOW validation may be triggered by, e.g.:

i. Increased water cut and water breakthrough (increased TDS) during normal asset Maturation.

Reservoir pressure depletion and reduction of line pressure will impact velocity in the line with

the consequence of an increased wall shear stress or reduced production and water drop-out.

ii. Sand production may occur, requiring a re-assessment of the CI effectiveness with solids.

iii. New wells coming online and feeding into an existing system can impact the IOW with

changes in composition, temperature, flow, pressure, etc.

iv. New chemicals to stimulate production, like foamers, or chemicals used for EOR (Enhanced

Oil Recovery) may be planned/initiated.

An example is the corrosion management process followed at Shell’s NAM field [8]. It is the job of

the Asset corrosion engineer in tandem with the production chemist to ensure that data is available

that supports the CIs effectiveness on the defined CI-IOW. This criteria is made available to

engineering and management staff in corrosion, chemistry operations and integrity. When conditions

are expected to occur outside this CI-IOW then new CI testing or field validation should be initiated.

For field validation of the CI a side stream evaluation may be utilised, like the Field Corrosivity

Toolbox (FCT) [80,81], where the corrosivity of the actual process liquids in the field is determined.

The corrosion rate can be measured on-line with proper the testing procedures, and CI-IOW

parameters can also be measured (e.g. pH, oxygen content, sampling to analyse water chemistry)

16

Conclusions

From this analysis the following conclusions can be drawn

i. A method for selecting and validating CI performance and operating a corrosion inhibition

system is proposed using the concept of a CI-IOW.

ii. The combined understanding of corrosion processes, Oil and Gas operations, and laboratory

test methods is crucial for effective CI selection, performance validation, deployment, and

operational surveillance.

iii. Employing a combination of engineering, operational, and laboratory CI experience and

capability is necessary to properly define a CI-IOW. This CI-IOW is needed to properly

identify needed testing, employing recognized methods developed for CI performance

validation.

iv. Corrosion Inhibition Management requires a defined work process to properly ensure CI test

program definition, testing, and implementation. Processes have been identified herein that

can ensure and improve the integrity of CS applications in corrosive systems in our Industry.

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