Paper No.

16CORROSION INHIBITOR TESTING AND SELECTION FOR E&P:

A USER’S PERSPECTIVE

S. D. KapustaShell Global Solutions

P.O.Box 38000, 1030 BN Amsterdam, The Netherlands

ABSTRACT

The selection of corrosion inhibitors for field use is often based on laborato~ and field testing of candidate products. Atpresent, there are no universally accepted tests to compare the performance and other properties of candidate products.This paper describes a test protocol that can help inhibitor users with the testing and selection of inhibitors for use againstCOJH2S corrosion in oil and gas production, and that allows the screening of a large number of candidates, in a relativelycost-effective manner. The selection is based on two criteria: performance (effectiveness) against corrosion at the expectedconditions, and compatibility with the injection and production systems, and with other chemicals. Performance is mostlyaffected by two factors: temperature, and to a lesser extent flow velocity. On that basis, three levels of increasing testingrequirements have been defined: conditions green, yellow, and red. Under mild or well-established conditions (lowpressure and temperature, existing operations) performance testing may not be required; however, compatibility testing isalways recommended.

Key Words: Corrosion, inhibition, testing, C02, H2S, pipelines, electrochemical, laboratory, standards

INTRODUCTION

Corrosion inhibition is one of the most commonly used methods for controlling corrosion of carbon steel equipment inoil and gas production, transportation, and processing. A large number of commercial corrosion inhibitors is available,and new products are being continuously introduced to handle more corrosive conditions and to meet more stringentenvironmental regulations. Inhibitor users are often faced with the prospect of selecting the best product from a long listof candidate products provided by the suppliers, without an easy way to compare the relative merits of these candidates.In a recent example, a total of 33 products from 10 suppliers were submitted for consideration for a pipeline project in theNorth Sea (ETAP = East Trough Area Project). The project schedule required that a product be identified and ready forfield use in a relatively short time, around 3 to 4 months. More details about this project are given below. This example istypical of the challenges facing the corrosion engineer who has to make a well-supported recommendation in a short timeand with limited resources.

The selection of a product for field application is usually, but not exclusively, based on results of laboratory or fieldtests. Ideally, laboratory selection tests should reproduce all the relevant parameters of the intended field application, suchas pressure, temperature, gas composition, flow conditions, etc. In reality, the time, effort and cost required to design andconduct a test that perfectly reproduces all the field conditions make this approach impractical. A more useful approachis to determine the critical factors that determine inhibitor performance, and then design the appropriate experiments totest these factors. No universally accepted standard method for testing corrosion inhibitors is currently available, andconsequently several users have developed their own approach; see, for example 1-5. Most of these tests focus exclusivelyon performance, and ignore the equally critical issues of inhibitor compatibility with other production chemicals, and withthe production system. However, in this user’s experience, compatibility problems are at least as likely to lead to failuresas are lack of proper performance (corrosion protection). Examples of compatibility problems encountered in actual useare: flashing of solvents leading to plugging of production tubulars and gas meter runs, foaming of sulfinol units due toinhibitor carry-over, reduced throughput caused by emulsion problems in separation facilities.

CopyrightCM999by NACE International. Requests for permission to publish this manuscript in any form, in pan or in whole must be made in writing to NACEInternational, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in thispaper are solely those of the author(s) and are not necessarily endorsed by the Association. Printad in the U.S.A.

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This paper outlines the corrosion inhibitor test and selection procedures used by Shell. The protocol is in principlesimilar to that proposed by BP1, but differs in some important aspects. For one thing, the intention here is to provideguidance to the corrosion engineer faced with a new inhibition application. Therefore, this is a higher level approach thatdoes not focus on the specific details of the tests. The main issues that are emphasised are: (1) laboratory tests cannot beexpected to precisely reproduce all field conditions, therefore an analysis of the main characteristics of the application isrequired to identify the most important factors to be tested; (2) inhibitor suppliers can provide sufficient information tomake a proper selection for many field applications; (3) the compatibility of corrosion inhibitors with other chemicalsand with the production system should be given as much importance as the inhibitor performance; (4) under well-mixedconditions, temperature and to a lesser extent flow are the variables that determine the performance of inhibitors in thetests; and (5) the volubility and/or water dispersibility of inhibitors is a critical factor in stratified flow.

The protocol includes the steps to identify candidate products for testing, describes screening tests to “weed out” thebad performers and final tests to select the best products, and tests of physical chemical properties, including compatibilityof inhibitors with the production system. The protocol has recently been applied to the selection of inhibitors for theprotection of pipelines in the North Sea, Malaysia, and the Netherlands.

OBJECTIVES AND SCOPE OF THE PROPOSED TEST PROTOCOL

The objectives of this test protocol are: (1) to provide the user with the means of identifying the best performingproducts for a particular application (downhole, pipelines or facilities) in a cost effective manner; (2) to reduce the needfor extensive testing; and (3) to ensure that the products selected are compatible with the production and treating systems.

This test protocol is not intended as an all-encompassing procedure covering all ranges of flow and environmentalconditions.

The protocol is intended for testing and selecting corrosion inhibitors (CI’S) for use in oil and gas production andtransportation environments containing C02 and/or H2S. The relevance of the tests will depend on the intendedapplication. For example, sulfinol or glycol foaming tendency will be relevant for inhibitors for gas/condensate pipelineswhich feed a sweetening or drying unit, but probably not for an oil/water pipeline. The proposed protocols can be used byinhibitor suppliers to support their recommendations. They can also be used to evaluate and develop the technicalcapabilities of testing laboratories for performing corrosion tests. For example, the accuracy of uninhibited corrosion testresults can be used, once sufficient experience is gathered from a number of laboratories, as the qualification criteria forthird-party laboratories.

INHIBITOR SELECTION PROCESS

A multi-step (cascading) process is used to identify the best inhibitor(s) for an application, while optimizing theutilisation of in-house and external resources. The process is schematically shown in Figure 1. The five key elements ofthis selection process are:

(1) the intended application needs to be fully analysed prior to initiating any testing,relevant to corrosion and inhibition, and determine the proper testing sequence;

(2) candidate inhibitors are identified;

to identify the critical factors

(3) the cheaper and faster screening tests are performed first to limit the most expensive testing to the best candidates;

(4) compatibility issues, such as the effect of inhibitors on water disposal, downstream processing, and the environment,should be considered early in the selection process, to avoid finding at the end of the process an unworkable(incompatible) or environmentally unacceptable product.

(5) final testing is performed under conditions that closely reproduce the most critical parameters of the application.

As corrosion engineers, we tend to emphasise inhibitor performance (effectiveness at reducing corrosion rates) as themain selection criteria. The approach presented here helps bring other factors, such as compatibility, to an equallyimportant level. In principle, the same process can accommodate inhibitor selection for all applications and conditions.In reality, a simpler approach should be used for “low risk” applications, for example established operations where therisks and concerns are known, or low temperature/ low corrosivity applications.

Review the intended application

The objectives of this review are: (1) to determine the expected corrosivity of the environment, that is, the magnitudeof the problem to be resolved, and (2) to identify the most significant corrosion factors, such as pressure, temperature,

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flow rates, presence of sand, bacterial contamination, etc. This analysis should also identify the acceptance criteria for thetest results, and the equipment that will be required to conduct the tests. It should also help to define the preferredphysical-chemical properties of potential inhibitors, such as oil/water volubility, thermal stability, low foaming tendency,etc.

The factors that determine the corrosivity of the environment have been extensively discussed in the literature 6“8,and willnot be dealt in further detail here. Their impact on inhibitor performance and selection are discussed below (section titled“Corrosivity and Corrosion Factors”), and summarised in Table 1,

Identify potential candidates

Candidate inhibitors can be identified by two main routes:

(a) rely on inhibitor supplier recommendations, ideally supported with data from laboratory tests or field experience(case histories). The information that needs to be provided to the suppliers to aid in their selection is discussedbelow (section titled “Information”) and is summarised in Table 2. The conclusions of the corrosion factors analysiscan also be discussed with the suppliers, to guide their selection. The use of a simple electrochemical (LPR) testunder standard conditions (kettle test at 60 ‘C, in a 5910NaCl solution, under 1 bar C02 pressure), is recommendedto serve as a quick screening tool by the suppliers in support of their recommendations.

(b) alternatively, candidate inhibitors can be selected from those already used or tested for similar applications,Unfortunately, most published reports (unless coming from the suppliers) omit references to a specific product.Many users, including Shell, have extensive in house data bases of inhibitors lab- and field-tested under a widerange of conditions, in terms of pressure, temperature, flow, and applications. This information is seldom madepublic, and in this user’s opinion, there is a need to openly share inhibitor test data among users and suppliers.

Evaluate. suppliers’ recommendations and data

The data provided by the suppliers in support of their inhibitor recommendations need to be evaluated to select the bestcandidates for further testing. The recommendation should ideally include a review of potential compatibility conflicts, forexample toxicity or low/high temperature stability. The information required for a proper selection may not beimmediately available for all products. In that case, the required data may have to be generated, or this step may have tobe postponed.

Perform screening tests

These tests are intended to: (1) verify the suppliers information, (2) eliminate non-performing products, (3) identify thebest performers for further evaluation, and (4) determine the physical-chemical properties of the products which mayaffect their applicabilityy. Ideally, a screening test should meet these requirements:

. be simple and low cost, to allow its use by most suppliers, even those with limited technical resources;

. be fast, to allow screening of a large number of products in a short time;

. be discriminating, to distinguish between good and bad performers.

The most common performance screening test methods are: wheel tests, kettle tests, and autoclave tests. The “wheel” or“bottle” tests follow the NACE recommended practice 9.The reproducibility and the significance of these tests are limited,and they should be avoided whenever alternatives are available. Kettle10and autoclave tests can be used to examinecorrosion inhibition effectiveness as a fimction of concentration, the water/oil partitioning characteristics, and even thevelocity dependence of performance (for example using rotating cylinder or rotating cage coupon holders). Provisions areusually taken to refresh the solution during the 1 to 7 days test duration, to reduce changes in the corrosivity of theenvironment caused by neutralisation of the test solution. The formation of more or less protective corrosion productscales (such as iron carbonate) maybe unavoidable given the small volume of solution. Scale formation does notnecessarily invalidate the test results, as experience shows that the test results can approximately match those obtainedfrom flow loops.

Table 3 shows a listing of the recommended screening tests for each intended application. The test coupons should beas representative of the expected service as possible. In the case of pipelines or flowlines, it is important to includerepresentative weldments, in terms of composition and welding procedures. Ideally, the tests should be performed at theexpected conditions of the application, in terms of solution composition, pressure, temperature, and concentration of

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corrosive gases. Alternatively, standard conditions (e.g., 1 bar C02, 60 “C, 1 to 5 % NaCl solution) can be used, if dictatedby lack of better information or equipment availability.

These tests are not relevant for determining the required inhibitor concentration. However, the concentration ofinhibitor can be varied (usually between 10 and 100 ppm) to determine the relative performance of different products.

Perform final testing

The best performing inhibitors selected above are further evaluated, under the expected most-severe field conditions interms of pressure, temperature, flow velocity, formation of scales, fluid composition (pH), etc. Ideally, all the criticalcorrosion factors should be reproduced. However, it is practically impossible to design and execute a laboratory test thataccurately reproduces all field conditions. Therefore, some compromises need to be made. In this protocol, final testingmeans evaluating the performance of corrosion inhibitors at the expected pressure (or partial pressure of corrosive gases),temperature, and flow velocity, while maintaining the composition (pH, Fez+and HC03- concentration) of theenvironment constant during the test period.

Final tests are often conducted in a flow “loop” 11-13,where the fluids are recirculated over the test specimens.Autoclave tests are also acceptable under some circumstances, provided that the contents of the autoclave are replacedperiodically to maintain a low concentration of corrosion products. Corrosion test loop geometry and equipment areextremely variable. Most loops are limited to operation with liquids only, although a few (Ohio University, U. of Tulsa)also handle gasfliquid mixtures, and are capable of recreating multiphase flow conditions. The geometry of coupons andcorrosion probes should be reviewed carefully to ensure that the results can be translated to flowline conditions. Theparameter used for scaling up the lab tests is usually the wall shear stress 11,although the Froude number has beenrecommended for slug flow 14.

These tests can provide a rough estimate of the required inhibitor concentration; the injection rate can only beoptimised using actual field data. Due to the high costs of these tests, only the most promising corrosion inhibitors shouldbe tested in this manner.

Field fluids are often not available for testing, and tests are usually conducted with “synthetic” fluids preparedaccording to the best available analytical information. However, this constitutes at best an approximation to the realsituation, since many components of the produced fluids (for example, organic acids, heavy metals, bacterial metabolizes)are not analytically determined, and they may have a strong influence on the corrosivity of the system, and on thebehaviour of the inhibitor. This is particularly important for oil/water pipeline applications, because of the widevariations in the corrosivity, wetting tendency, emulsion tendency and solvency of crudes.

Perform a Ml compatibility analysis and testing

In the context of this paper, compatibility encompasses all aspects of the interaction of corrosion inhibitors with theproduction system, other than their performance. In this sense, compatibility is understood as “can live and operatetogether”. In order to engineer and operate the inhibition system properly, the inhibitor must be compatible with all partsof the production system, including materials of construction, other production chemicals, and the downstream processingof water and hydrocarbons. The compatibility concept can be expanded to include environmental issues, such as toxicityto marine life and disposal of contaminated streams. Environmental testing and categorisation are usually carried out bythe inhibitor suppliers.

Offshore oil and gas production operations pose some unique challenges to the design of an inhibition system. In themore traditional projects, the producing wells are housed at or near the central facilities platform, for example in welljackets, and are connected to the facilities via short flowlines. This approach is in many aspects similar to onshoreoperations, with the added constraint imposed by environmental limitations to storage, use and disposal of chemicals. Inthe new subsea projects, such as Eastern Trough Area Project (ETAP) in the Central North Sea, subsea oil and gasproduction wellheads are linked via subsea pipelines to processing facilities often located tens of kilometres away. Thecompatibility issues are complicated by the possibly long residence times of the inhibitors in the low-temperature injectionlines, by the use of a wider variety of materials, and by the practical difficulties of direct intervention in case of problemssuch as plugging of injection valves or leakage of seals.

Because of their complexity, compatibility should be addressed on a project-specific basis. The following sectionsdescribe a few of the most important issues that need to be addressed.

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Thermal stability

Stability concerns include the separation of distinct phases, increases in viscosity due to ageing (polymerisation), lossof effectiveness due to decomposition, and the formation of solids. Most organic inhibitor molecules are stable up to about120 ‘C4, however loss of volubility or dispersibility of the formulation can occur at lower temperatures. The inhibitorshould be stable at the temperature of operation (up to 160 ‘C) for the time required to provide protection, during storageand transportation at ambient temperature (usually -10 to + 50 “C), and during long term high temperature (up to 120 “C)exposure in the annulus, in case of downhole injection. IR analysis has been used to determine changes in molecularstructure 4’15,however these changes do not necessarily equate to a loss of performance.

Compatibility with iniection and production system materials

Inhibitor storage tanks and transfer lines are usually constructed ofAISI316 SS. Some concentrated inhibitorsolutions, such as amine chlorides or quats, can be corrosive to this material. Inhibitor formulations can also have adetrimental effect on the mechanical and chemical properties of elastomeric seals, resulting in swelling, loss ofmechanical strength (extrusion), and explosive decompression in case of sudden changes in pressure. Specific testingprocedures should be used to evaluate these effects.

Phase behaviour

Solvent flashing may occur at the point of inhibitor injection into the production system. This can result in theformation of a viscous fluid, or worse yet, solid substances that could plug the injectors. Severe corrosion of downholetubulars, and plugging of gas plant meter runs have resulted from solvent flashing. Shell has performed extensive studiesto model the behaviour of solvents in high pressure, high temperature hydrocarbon streams, and has a large data base ofrecommended solvents for different downhole and pipeline applications.

Downstream processing

Potential concerns include, but are not limited to, the formation of water/oil emulsions in the separation facilities,foaming in absorbers and flash vessels, inhibitor-induced fouling in condensate stabilisation vessels, etc. Another issuethat must be considered for offshore operations is the impact of the inhibitor on the quality of overboard water. Bothblender and “seltzer” tests are fairly common5, The use of actual fluids is particularly important to determine the foamingand emulsification tendencies. For example, corrosion products such as iron sulphide can act as powerful stabilisers ofemulsions.

The formation of solids on reboiler tubes should also be evaluated. Most inhibitors are thermally stable at the relativelylow temperature needed for condensate stabilisation or glycol re-concentration (usually around 100 ‘C). However,decomposition and fouling may occur at higher temperatures, for example if condensate is fed to a reformer.

Compatibility of the corrosion inhibitor with other chemicals

A number of production chemicals can be present at the wellhead and into the flowlines, for example, scale inhibitors,paraffin solvents, biocides, oxygen scavengers, and hydrate control additives, such as methanol, glycol, or the newerhydrate growth inhibitors (HGI’s). The interaction of the corrosion inhibitors with other chemicals should be evaluated ona case by case basis. Testing should include the effect of corrosion inhibitors on the performance of the other productionchemicals, as well as the effect of these chemicals on the performance of corrosion inhibitors. Some chemicals which havebeen found to affect the performance and stability of corrosion inhibitors are: scale inhibitors, aldehyde-based biocides,and asphaltene inhibitors. On the other hand, sulphite-based oxygen scavengers may actually enhanced the performanceof corrosion inhibitors,

Field testing

Ideally corrosion inhibitors should be field tested, in a small scale, short time trial (for example, a few flowlines orwells in a large field), before full deployment. In reality, field testing is only possible in existing operations, and eventhen it is difficult to implement the test and to evaluate its results, One of the main difficulties is obtaining representativedata from short term field corrosion monitoring. This is particularly true in the case of pitting corrosion caused by waterdrop accumulation at the bottom of the line.

The most important factors in a successful field test are: (1) to establish limited and clear objectives jointly with allstakeholders (inhibitor supplier, operators, corrosion specialists); (2) develop a robust plan for monitoring corrosion ratesover an extended period; (3) assign roles and responsibilities to all participants; and (4) evaluate the test results promptly.Moreover, an “owner” of the test, who will drive the test and champion its successful conclusion, should be clearlyidentified and recognised by all stakeholders. The owner could be, for instance, the asset manager, the corrosion engineer,or the field supervisor.

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Inhibitor volubility and its effect on performance

Inhibitors are usually classified as water soluble or oil (hydrocarbon) soluble. In reality, most inhibitors showing atleast partial volubility or dispersibility in both phases. It maybe more appropriate to state that inhibitors partitionpreferably to one or the other phase. A thorough analysis of the intended application is needed to design the appropriatetesting procedure, taking into consideration the candidate inhibitor volubility preferences.

For example, “oil soluble” inhibitors often require at least a small volume of oil to perform adequately. They will showpoorer performance than “water soluble” inhibitors in tests conducted in the absence of oil, or even in water/oil partitiontests. This means that typical partition tests, for example as described in BP’s test protocol 1,will tend to favour watersoluble or highly water dispersible products. Are these tests meaningful? The answer depends of course on the flowcharacteristics of the system that will be protected. Partition or water-only tests maybe appropriate for selecting inhibitorfor pipelines operating in stratified flow, where a continuous water phase will exist at the bottom of the line. However, ifthe flow regime in the pipelines is such that full mixing of the oil and water phases can be achieved, the tests should beconducted using a representative oil/water mixture and sufficient stirring to allow mixing of the phases. Again, analysisof the field conditions should indicate the type of testing which is more relevant for each particular application.

Corrosivity and corrosion factors

The factors that determine the corrosivity of oil and gas production environments, and the methods for predictingcorrosion rates have been extensively discussed in other publications 3,4, and references therein], and will not bediscussed in further detail here. The main factors include: (1) concentration of corrosive gases, C02 and H#3; (2)temperature; (3) water composition, mainly pH, and concentration of “aggressive” (Cl-, SOd=,organic acids), and“protective” (oil, HC03, inhibitors) species; and (4) flow velocities. Metal composition and microstructure (heattreatment) can also have a strong impact on corrosion rates,

Impact on inhibitor testing

Simulating all field conditions in a laboratory setting can be complicated, costly, and impractical. Therefore, laboratorytests should only address the most critical corrosion factors identified above. In a practical sense, the three factors whichhave the strongest influence on the type and extent of inhibitor testing are: (1) the predicted corrosivity of theenvironment; (2) the temperature; and (3) the flow velocity. The metallurgy of the test coupons, more specifically the useof actual welds, is of critical importance for pipeline inhibitor selection. The severity of the inhibition conditions can beclassified as:

(a) Condition Preen - predicted uninhibited corrosion rates below 10 mrn/yr; temperatures below 60 “C, and mixtureflow velocities between 1 and 5 rrh. Many products have shown adequate performance under these conditions if theirphysical properties (volubility, dispersibility) are adequate to the specific application, and if they are compatible with theproduction system, Many laboratories, including most inhibitor suppliers, have the necessary equipment to screenproducts for these conditions, Experience has shown that the target inhibitor concentration, for testing, should be around10 to 50 ppm, based on water phase.

(b) Condition Yellow - predicted uninhibited corrosion rates between 10 and 50 mrrdyr, temperatures between 60 and120 “C, and flow velocities between 5 and 15 m/s. The feasibility of inhibiting these conditions has been demonstrated inlaboratory tests, and there is a small but growing amount of field experience (particularly below 100 ‘C). Some inhibitors,suffer hydrolysis (decomposition) in this temperature range, Some inhibitors, may lose their effectiveness at the highertemperatures. Velocity effects may become noticeable at flow disturbances, such as bends, valves, welds, etc. Experiencehas shown that inhibitor concentrations of 50 to 200 ppm, based on water, are needed in the absence of oil or condensate,and 20 to 100 ppm if oil (rather than condensate) is present.

(c) Condition red - predicted uninhibited corrosion rates above 50 mm/yr, temperatures above 120 “C, mixturevelocities above 15 m/s. Also applicable to sour conditions, with an H2S concentration above about 5 %, due to thepossibility of pitting corrosion. The feasibility of inhibiting these conditions has been demonstrated in laboratory tests,and also in several applications (Shell Oil’s Thomasville and Fandango fields, Shell Canada’s Caroline field, Texaco’sErskine field). Careful testing and selection of the right inhibitors, and proper design of the inhibition system, areessential. A limited number of test facilities are available world-wide, particularly for high velocity testing. The thermalstability of inhibitors becomes critical. The performance of many inhibitors falls dramatically at temperatures above 140-150 ‘C. Inhibitor concentrations in excess of 200 ppm are usually needed to achieve good performance. The presence ofelemental sulphur significantly increases the potential for pitting corrosion, requiring much higher inhibitorconcentrations.

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These categories are schematically shown in Figure 2, The specific set of tests which are recommended for each ofthese conditions are summarised in Table 1.

Information for the chemical suppliers

In order to provide good recommendations, suppliers should be provided with relevant information about the intendedapplication of their products. An example of the information needed is shown in Table 2. As a minimum, they need toknow the expected environment (in terms of pressure, temperature, gas and liquids compositions) and flow regimes(gas/liquid velocities and/or flow patterns). They also should be informed of other factors that may affect the corrosivityof the environment, such as changing production conditions, sand production, or the applicability of their product, such astype of operation, environmental concerns, accessibility to the area, etc.

Information from the chemical suppliers

An advice to use a certain product for a specific application should ideally be accompanied by the following supportinginformation:

safety data sheets with as much information as possible on the chemical composition;information on the environmental acceptability, including toxicity, biodegradability and oil/water partitioning data.For application in the North Sea area include the U.K. Department of Trade and Industry (DTI) classification;physical chemical properties determined and reported as described in this report;compatibility of product, particularly of solvents, with non-metallic components of the inhibitor injection and theproduction systems;compatibility of inhibitor with other production chemicals, such as scale inhibitors, demulsifiers, biocides, H2S oroxygen scavengers, etc.a method for the quantitative determination of the inhibitor in field fluids;chemical type of the ingredients and solvent;expected corrosion rate with the product in the prospective application;laboratory test data, including the results of the bubble vessel test obtained and reported consistent with this report;recommended concentration and application method;case histories of any application whether successful or not.

It is recognised that not all this information maybe immediately available for all products. This list maybe used as aguideline to the type of information that Shell requires before beginning in-house or third party testing of recommendedproducts.

Tests of physical chemical properties

The main physical chemical properties which are of interest for the design of the inhibition system, and morespecifically for the selection of a product for a particular application, are:

. volubility of CI in carrier media (oil, water, glycol);

. foaming and emulsification tendency;● phase distribution (partition between aqueous and hydrocarbon phases) of the formulation and its implication for

corrosion protection;. effect of short term exposure to high temperatures, for example decomposition, loss of effectiveness, or tendency to

form sticky deposits in gas production systems;. effectiveness after long term storage at high temperature, referred to as downhole stability test, for those wells

where CI’s are stored in the casinghubing annulus for extended periods;. stability and effectiveness of CI’s after exposure to simulated glycol re-boiler conditions;. stability and tendency to form deposits when exposed to condensate stabiliser conditions.

These properties, with the notable exception of oil and water volubility and thermal stability, may not necessarily havea direct effect on the inhibition performance. They do impact other issues, such as the compatibility of inhibitors withdownstream processing and the design of the injection system. The types of tests which are considered necessary for eachprospective application (e.g., downhole tubing or pipeline, gas or oil production) are summarised in Table 3. The testingprocedures are available from Shell. Some of the tests provide an absolute measurement of the specified parameter, forexample volubility in water. Other tests, such as foaming and emulsion tendency, only provide relative results, which areuseful for comparing different products but cannot be directly translated to expected field behaviour. As in the case of

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performance testing, laboratory testing of the physical chemical properties using actual field fluids is recommended,ideally prior to field use but at least soon after start-up of production.

Application of the protocol to the ETAP export pipelines

ETAP (East Trough Area Project) is a new development in the UK sector of the North Sea. It comprises several oil andgas reservoirs, which will be evacuated via two parallel, 22-km long pipelines to a central production platform. Thetemperatures in the pipelines will range from 153 to 65 “C, and the pressures from 131 to 27 bar. The associated gascontains 0.9 to 1.470 C02, which makes the environment potentially very corrosive. Corrosion inhibition will be requiredfrom the start-up to protect the carbon steel pipelines,

A review of the expected operating conditions revealed that the most critical corrosion factors were: (1) hightemperature; (2) high flow velocities, in excess of 20 nds at the pipeline outlet; and (3) high potential corrosivity, up to 30rnm/yr measured in flow loop tests. In addition, other chemicals would be injected into the pipelines: scale inhibitors,asphaltene inhibitors, biocides, oxygen scavengers, and possibly hydrate inhibitors. On the basis of this analysis, the mostimportant characteristics of inhibitors that needed to be evaluated were: performance and stability at high temperature,flow (shear stress) stability, and compatibility with other chemicals.

A total of 33 corrosion inhibitors were submitted by 10 suppliers for consideration. An initial evaluation of the dataprovided by the suppliers reduced the number to 16 candidates for screening. The screening was performed using highpressure, high temperature autoclave tests. Some of the pipeline welds showed a remarkable tendency to localisedcorrosion, therefore protection of the weld H&Z was established as the main performance criteria. The top 4 candidateswere further tested using a high shear stress “jet impingement” apparatus 12.Only 2 products showed acceptableperformance under those conditions, and were recommended for field use. Both products were compatible with the otherproduction chemicals, but the ratio of concentrations had to be properly balanced.

One of the lessons learned from this exercise is that autoclave tests provided a relatively easy method for evaluating theperformance of inhibitors on welded metal, with results which were consistent with those of the more expensive highshear flow loop test.

A note on quality assurance

The relevance of the inhibitor selection and testing procedures depends on the implementation of a strong qualityassurance programme, to ensure that the products used in the field are consistently the same as those tested and selected.In the past, the industry attempted to “police” the quality of delivered inhibitors, for example by extensive analysis ofproducts (test and reject policy). The recommended approach to quality assurance is to follow ISO-procedures. Basically,the emphasis should be on establishing proper processes, procedures and key performance indicators (KPI’s) andretaining full traceability of products and materials, rather than relying on spot checks to identify our-of-complianceproducts. The KPI’s are specific to each product and application, but examples include: % conversion of base reactants,reactor conditions, viscosity, diffraction index, performance in mutually-agreed standardised tests, etc. A statisticalapproach to batch analysis can also be part of the procedures.

CONCLUSIONS

Inhibitor selection is the first, and possibly the most critical, step in the design of an effective corrosion inhibitionprogramme. Laboratory testing is often used for selecting inhibitors, but it is always an approximation to the real system,as not all field parameters can be reproduced in a laboratory set-up. Laboratory tests tend to become increasinglysophisticated, and correspondingly more expensive. However, other alternatives, such as field experience, supplier’srecommendations, and field testing, can be used. In addition, commercial and business factors weigh heavily on theselection decision.

The recommended multi-step testing procedure is intended to ensure that effective products are identified and selected,while at the same time reducing the cost and effort of testing. Most test protocols focus exclusively on inhibitorperformance. Performance testing is, however, not always required, particularly for low risk, low corrosivity applications,and when a reputable supplier is involved. The testing requirements increase with the corrosivity and criticality of theapplication. On the other hand, chemical and process compatibility testing is always required. Compatibility includes: (1)materials in the injection and production systems (tanks, lines, seals, gaskets); (2) other production chemicals (scaleinhibitors, wax inhibitors, demulsifiers); (3) downstream processing (potential for foaming or emulsions in separators,strippers, stabilisers); and (4) the environment.

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Laboratory testing using field fluids is a recommended step to verify the test results obtained with synthetic fluids, asseveral important inhibitor properties, such as performance, volubility, emulsification and foaming tendency, depend onthe actual composition of the water and hydrocarbon phases,

As a concluding note, corrosion inhibitor testing procedures are still evolving, as new information allows a betterunderstanding of the critical factors that affect field performance. For example, a few years ago the effect of turbulenceassociated with slug flow was identified as a serious problem for inhibition in the Alaska pipeline. An ongoing jointindustry project is now looking at the effect of solids in removing inhibitors from solution by adsorption. Other importantfactors will undoubtedly be identified as more field experience is gathered. This means that our test protocols will alsoevolve.

REFERENCES

1. McMahon, A.J., and Groves, S., “Corrosion inhibitor guidelines: a practical guide to the selection and deployment ofcorrosion inhibitors in oil and gas production facilities:, BP Sunbury Report No. ESR.95.ER.050, Sunbury (1995).

2. Garber, J.D., “Comparison of various test methods in the evaluation of C02 corrosion inhibitors for downhole andpipeline use”, CORROSION/94, Paper No. 94042, NACE International, Houston, Texas (1994).

3. Palmer, J.W., Dawson, J.L, Ulrich, T., and Rothwell, A.N., “Inhibition of weld corrosion under flowing conditions -the development of test procedures”, CORROSION/93, Paper No, 119, NACE International, Houston, Texas (1993).

4. Wu, Y., “corrosion inhibitor screening tests and selection for field applications”, CORROSION/94, Paper No. 43,NACE International, Houston, Texas (1994).

5. Achour, M.H., and Kolts, J., “Laboratory testing of inhibitor persistency at high velocities”, CORROSION/93, PaperNo, 116, NACE International, Houston, Texas (1994)

6. de Waard, C,, and Lotz, U., “Prediction of C02 corrosion of carbon steel”, CORROSION/93, paper No. 69, NACEInternational, Houston, Texas (1993).

7. Dunlop, A.K., Haskell, H.L. and Rhodes, P.R., “Fundamental considerations in sweet gas well corrosion”,CORROSION/83, paper No. 46, NACE International, Houston, Texas (1983).

8. de Waard, C., Lotz, U., and Dugstad, A., “Influence of liquid flow velocity on C02 corrosion: a semi-empiricalmodel”, CORROSION/95, Paper 95128, NACE International, Houston, Texas (1995).

9. “Wheel test method for evaluation of film persistent inhibitors for oil field applications”, Report 1D182, NACEInternational, Houston, Texas (1982).

10.Annual Book of ASTM Standards, Vol. 03.02, Standards Gl, G31

11. Jepson, W.P., “Model for sweet corrosion in horizontal multiphase slug flow”, CORROSION/97a, Paper No. 97602,NACE International, Houston, Texas (1997).

12.Efird, K.D., Wright, E.J., Boros, J.A., and Hailey, T.G., “Experimental correlation of steel corrosion in pipe flow withjet impingement and rotating cylinder laboratory tests”, Corrosion, Q No. 12, pp. 992-1003, NACE International,Houston, Texas (1993).

13.Dawson, J.L., and Shih, C.C., “Electrochemical testing of flow accelerated corrosion using jet impingement rigs”,CORROSION/87, Paper No. 453, NACE International, Houston, Texas (1987).

14.Chen, T.Y., Moccari, A,A., and McDonald, D.D., “The development of controlled hydrodynamic techniques forcorrosion testing”, CORROSION/91, Paper No. 292, NACE International, Houston, Texas (1991).

15.Teevens, P.J., “Corrosion control considerations for the production of very sour gas wells”, in Corrosion control andmonitoring in gas pipelines and well systems, pp. 134-155, NACE, Houston, Texas (1989)

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Table 1. Corrosion factors and corresponding testing requirements

Main coneems Recommended tcsta watch out for

Temperature “C <60 Green conditions,no special concerns &tWOingt@5, standardCOSlditiOtlS low temperature stabifity

60-120 yellow conditions,sane inhibitorlose HT perforrnanee,HT stability, solnbility thermal stabilityat the high end of range

effediveness due to higher temperatures

>120 Red conditions,thermaldecomposition+ HT performance,HT stability, deposits high shear, inhibitordecomposition,

resorption, few acceptable inhibitors pitting corrosionif HZSpresent

Mnture vebxfty <1 water drop out oil/waterpartitioning aan&depositsin pipelines

M 1-5 standardconditions,no sp%ial eoncetns saeening tests, staodard conditions kettfetests acceptableif environment

kept constant

5-15 inhibkor removal by shear or turbulence roWing cage, flow loop weld corrosion

>15 inhibitorremovaf,erosion mrrosion high shear,jet impingement benda,flow disturbanms, sand erosion

Ffow pattern* Sw water drop OULTOL** corrosion oif/waterpardtiorLTOL** highBS&W

(see ah mixture St inhibitor removal by turbuferree,bubble rotating cage, flow loop, stationary slug high temperatures

eloeity mw.

ement

AM inhibitor rernovrdby shear rotating cage, flow loop, high shear high turblderrce,high k mperatrrre

BS&W % <1 Green eonditiorrs Green both oil and water soluble may be OK

1-20 Green conditions Green low velrxity water drop out, flow regime

>20 More a “water” system water partitioning or volubility water solublepreferred for pipelines

Corrosivity *** <10 Green emrditions Green

rnrs@r 10-50 Yellow test at actual P and T retksh SOhlthl,minimisesealing,high

shear

>50 Red full testingprocedure few labotatoties ean run these tests

H2S %m o Green conditions Green

o-1 FeS Scaling/protection,some inhibitors Add H2S to green teats electrochernieaftests may not work,

ineffective,others are enhaneed quats may work better

>1 Pitting or crevieecorrosion,elemental long term exposure,creviee corrosion high salinity, veloeityor temperature,

sulphur, ittftibkorlose effectiveness elementalsulphurcorrosion

* Ffowpatterns: SW = stratified wa~, S1= intermittent slug A/D = annrdardispersed** TOL. tq of the line corrosion, *** Corrosivityealcofatedby ref. 8. WY

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Table 2. Typical information to be given to corrosion inhibitor suppliers for screening tests

I Facility

I Material

I Diameter

-

Len thInlet tern ratureInlet ressureGas production rate

l==C02 concentrationH2S concentrationCondensateWater ex knock outWater com itionEnvironmental

or expected life time

Value or range Unit Remarkduring life timeGas or oil pipeline Oil/condensate properties, such as

viscosity, density, compositionX-65 Composition, heat treatment and

production route

10 I km I100-70 ‘c60-40 I bar

0.5-0.4 I MMsm3/d I

4-3 I mol 70

0-1oo PPm.

0.5 m3/dayNaHC03, TDS, pH, organic acids, etclog pOW,bio-accumulation LC50

Im I Alternatively, give inhibited corrosionrate requirements

Table 3. Recommended screening tests of physical properties, listed for the possible envisaged field applications ofcorrosion inhibitors. Note that for each application standard performance corrosion test is also recommended

Application Tubhg Top-side pipe and flOWlines

Test Batch Continuous Batch Continuous

Gas Oil mukiph liquid wet gas lines

ase gas tine full lines with glyml

Volubility x x x x x x

Foaming x x x x x x x x

E?mrdsitication x x x x x x x x

Down-hole x x x x x

stability*

Stickydeposits x

Glycol rebciler x

Phase x

separation

* For those abwn-hole injections where the CI solutionx is stored in the casing for longer periods.

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F@e 1. Inhibitor selection procss

CA Conditiongreen: as:b~~i, but ~ ‘~~nd~~ YeIIOW as above but add ! Condition red: high

Evelaaitiy elkot, waWgeomeby ~FMMting cylinder or rot. cage

~shear testing neededsWeld damage more

~ Slikely, Hard to prevent:.- ~aoaling in autoclaves

u

+ 10? gCondiiion Yeltow thermal stability at ;Condition red: thermal

Kettle cx aukdaves aqptab[a ;Utehighend ~atatility, flow effeots al

BPhy#co-clwmi@ prop#i$

~lower velooitiea~t:t ,.,,,,,,,,, r,,,,.,,, #,tt##itl

. .... ...... ... ... . ..... ......

60 120 1temperature ‘C

Figure 2. Effect of flow velocity and temperature on inhibitor testing requirements.

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