pragmatic effects of flow on corrosion prediction

7/28/2019 Pragmatic Effects of Flow on Corrosion Prediction

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PRAGMATIC EFFECTS OF FLOW ON CORROSION PREDICTION

Binder Singh, Kana Krishnathasan,IONIK Consul ting – JPKenny,15115 Park Row, Suite # 340

Houston, Texas, USA.

ABSTRACT

Recent design work regarding deep Gulf of Mexico (GOM) subsea flowlines hasemphasized the need to identify, develop, and verify critical relationships between corrosion

prediction and flow regime mechanisms. In practice this often reduces to a pragmaticinterpretation of the effects of flow on corrosion mechanisms. Most importantly theidentification of positions or sites, within the internal surface contact areas where the maximumcorrosion stimulus may be expected to occur, thereby allowing better understanding,mitigation, monitoring and corrosion control over the life cycle. Some case histories have beenreviewed in this context, and the interaction between corrosion mechanisms and flow regimesclosely examined, and in some cases correlated. Since the actual relationships are complex, itwas determined that a risk based decision making process using selected ‘what if’ corrosionanalyses linked to ‘what if’ flow assurance analyses was the best way forward. Using thismethodology, and pertinent field data exchange, it is postulated that significant improvementsin corrosion prediction can be made. This paper outlines the approach used and shows howrelating corrosion modeling software data such as that available from corrosion modelsNorsok M506, and Cassandra to parallel computational flow modeling in a targeted manner can generate very noteworthy results, and considerably more viable trends for corrosioncontrol guidance. It is postulated that the normally associated lack of agreement betweencorrosion modeling and field experience, is more likely due to inadequate considerationof corrosion stimulating flow regime data, rather than limitations of the corrosion modeling per se, thus tending to switch the immediate onus for corrosion prediction accuracy and reliabilityaway from corrosion modeling over to the flow regime side. The subject matter is ongoing andit is envisaged that the predictions will be benchmarked against real field data as projectsadvance into each life cycle and generate field data and experience. This approach isexpected to better quantify the lessons learnt aspect of each project, thereby helping improvefuture designs in a more cost effective manner, as well as attending better to challenges in theareas of deepwater and future arctic pipeline corrosion and integrity management, whereuponthe need for inherently safe designs has become far more emphasized.

Keywords: ALARP (As Low As Reasonably Practicable), CO2 corrosion, corrosion allowance,corrosion resistant alloy (CRA), decision gates, erosion, fit for purpose solutions, inherentlysafe design, localized corrosion, life cycle performance, risk basis, top of line corrosion.

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Paper No.

09275



INTRODUCTION

The development of deepwater pipeline infrastructure in the Gulf of Mexico has seen rapidgrowth over the past few years. There are many new (greenfield) projects and many more tiebacks into existing (brownfield) networks. This makes it important to acknowledge, identify,

and develop, the critical relationships between corrosion prediction and flow mechanisms.Most significantly the identification of sites at which maximum corrosion stimulus can beexpected thus allowing better understanding, mitigation, monitoring and corrosion control over the full life cycle. A number of case histories have been assessed in this context, and theinteraction between CO2 corrosion mechanisms and flow regimes has been reviewed for manydesign campaigns. The actual relationships are complex, and for practical reasons a riskbased decision making procedure using ‘what if’ corrosion analyses linked to ‘what if’ flowassurance analyses was considered the best way forward.1-8

With this methodology, and field data exchange, it is believed significant improvements incorrosion prediction are feasible. This paper shows how relating corrosion modeling data such

as that available from Norsok M506, and Cassandra software, to parallel flow modeling in atargeted manner can generate very noteworthy results, and sometimes unexpected trends for corrosion control. The methodology also provides good semi-quantitative arguments for

justification and a wide range of references have been used, the most pertinent of which arelisted 1-30. The project started of as an internal venture and is currently a work in progress andthis paper therefore presents outlines only, with the intention for a company ‘go-by’ guidancenote to be implemented in the near future.15

It is postulated that the lack of agreement between corrosion modeling and field experience, isdue to the inadequate acceptance of the impact of corrosion stimulating flow regimes, rather than limitations of the corrosion modeling itself; thus switching the onus for corrosion predictionaccuracy and reliability away from corrosion modeling over to the flow regime modeling side.The subject matter is new and ongoing and it is envisaged that the predictions will bebenchmarked against field data as case histories advance and new projects move into theexecution and operations phase. 8,9,15

This approach has helped streamline corrosion and integrity management for deepwater pipelines. Normally this is heavily dependent on the soundness of the original design, since lifecycle rehabilitation, repair and even basic maintenance issues are so costly. Hence theconcept of inherently safe design (ISD), and its importance within the rigorous auspices of riskand consequences involved. Whereupon critical design decisions take into account the effectsof failure upon the asset, personnel safety, and within the context of the environment and musttherefore be maintained as low as reasonably practical (the ALARP condition). With thesedrivers in place it is possible to merge and reconcile CAPEX and OPEX so that resources andcosts are better shared for mutual benefit. 8,13,15 This becomes particularly important as newpipelines (tie backs) are introduced into existing (already corroded) infrastructure, whereuponthe design issues can become far more sensitive.

As a rule carbon steel (e.g. API X65 or X70) is normally the material of first choice, but in thecase of internal fluids being too corrosive, intervention solutions can be contemplated, typically

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engaging internal coatings or internal CRA lining or cladding. In this eventuality the costs canbe prohibitive often more than 10 times the equivalent cost of steel, however for deepwater assets the use of CRA liners or cladding can prove to be an acceptable solution, in which casethe stainless steel or nickel based alloys as thin, 3-4 mm liners can be selected over susceptible portions of flowline only, thus reducing the cost burdens substantially. The benefit

of reduced corrosion issues, less inspection, greater confidence in operability, minimizeddowntime periods, gives a much reduced risk of failure, which is vital in deepwater projects,and indeed for future prospective arctic applications whereupon similar or even harsher environmental parameters may apply.1,8

Nevertheless whilst carbon steel may be selected it does have more challenging requirements,such as the need for better understanding, accuracy and reliability of the materials andcorrosion performance. In this regard the main obstacles are often found to be related to thecorrosion allowance (CA) aspect. The CA is the designer’s tool providing contingency for corrosion control. The parameter essentially provides for a margin of safety to cover for corrosion wall thinning during the design life 8-11. The few extra mm (typically minimum of 3mmand maximum of 10mm, and frequently a precautionary 1mm for dry non corrosive lines)utilized for this purpose can be significant for long flowlines and often the corrosion engineer isunder pressure from project managers to reduce this value to help keep CAPEX costs down.

Hence technical arguments and history or experience based data is vital to help justify suchadditional steel. Clearly this is best done by an improved understanding of corrosion due tocorrosive gases erosion, microbial activity (MIC), deadleg corrosion and in particular flowassisted corrosion (FAC). In practice the latter is probably the least attended to, and hence theemphasis of this paper. In reality FAC encompasses all the critical mechanisms mentioned,namely uniform corrosion, erosion, impingement, high shear, biofilm formation, MIC/deadlegactivity etc. The normally used pitting resistance equivalent (PRE) and the critical crevicetemperature (CCT) parameters (see Table 1), are related to static bench top experiments and

are frequently overridden by data in the field which is stimulated by flow parameters duringoperations. Thus the natural outcome of examining the link between corrosion and flowassurance phenomena.

PERTINENT FLOW ASSURANCE

Generally for subsea pipelines flow assurance covers all multiphase transport phenomena.Diligent design methods, knowledge and skills are needed to ensure safe, continuity of fluidstransport from reservoir to topsides processing plant. The main areas involve steady state andtransient multiphase flow, hydrates, sand, oil, emulsions, wax, scale and corrosionphenomena. Multiphase fluids transport cannot be exploited in a safe, controlled way unless

the dynamic behavior of the flow can be predicted with sufficient reliability. This is crucial withrespect to concept phase feasibility studies, optimal design of pipelines and safe operations.The interaction between corrosion/scaling and flow assurance can therefore be instrumental indetermining true production rates, and software tools such as the OLGA® (Scandpower) codescan serve to give reliable predictive modeling. Providing an accurate and reliable link betweenflow assurance and corrosion modeling is thought to be one of the main challenges facing theindustry today. The overriding performance fingerprint is often best recognized as the bath tubcurve, (Figure 1). Preliminary HAZOP studies can be usefully deployed to help in this regard,

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and to help facilitate this better, corrosion must be considered a functional hazard. Once that isaccepted the need for a soundly planned and diligently applied corrosion managementstrategy becomes self evident and a pronounced requirement for important deepwater subseainfrastructure and tie backs.

18,21,22

The onset of problems with corrosion integrity during early life is critical, though mid life is oftenbetter managed since field life is quite often well below design life and so options and time canbe expected to favor planned retrofit if needed. Life extension beyond the wear out zone tendsto be more applicable to older (brown field) projects whereupon original design life’s have beenexceeded and continued production is still required.8,14 Some of these aspects as related tocorrosion are further illustrated in Figures 2 to 4.

CHALLENGES

The immediate controversy has nearly always been whether to design for build or to designfor life cycle fitness for purpose. The former (design for build) is most popular and mosteffective for CAPEX as it passes the responsibility (and therefore costs) for maintenance to theoperations phase. The latter (design for the life cycle) is difficult and more expensive withregards to CAPEX, as it demands interpretation beyond the engineering codes, and reliesmore on experience, judgment and stretches design budgets. However the net benefit is thattotal project costs are reduced, designs are safer, and expensive costs associated withfailures, loss of performance, and loss of production (forced shutdowns) as well as costly infield repairs replacements are minimized. It is now accepted that the major threat to theflowline asset is internal corrosion, rather than external cathodic protection (CP) issues, whichare quite effectively addressed by code compliance to coating and CP standards. The statisticsvary but overall it is found that internal corrosion causes around 15% of onshore and up to50% of offshore pipeline failures.8 With the criticality of deepwater pipelines in the GOM, notsurprisingly a great deal of attention is focused on the design basis for the latter, and to thateffect new regulations demanding integrity management plans at design have now beenintroduced. 8,23

The problem is that there are no commonly accepted codes of practice to address internalcorrosion, and so the only re-course has been to utilize the best available corrosion models. Inthis regard CO2 corrosion mechanisms are dominant, and traditionally the models have tendedtherefore to be based on empirical studies or the deterministic approach of De-Waard andMilliams. 9 However in practice even the ‘best’ models rarely match real time, accelerated, or field results, and this is attributed most often to failings in modeling reliability, inappropriateassumptions and inaccurate data inputs, leading to unfitting safety margins, and the skewing of performance data by secondary parameters such as biofilming, microbially influenced

corrosion (MIC), crevicing, sanding, etc. 8, 15 One way to address this mismatch has been toassume greater levels of safety margin by looking at worst case conditions applied to thedesign life. However this can lead to over -conservatism with expensive reliance on CRAs, or even under-conservatism with premature failures. Hence the focus of this work, to help better represent the pertinent parameters such as flow assurance in the detail design and verificationor appraisal process.

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Another variable impacting life cycle performance is the length of pipe, since the developmentof flow regimes is not only time dependent but also length dependent, and thus highlyinfluential on the corrosion activity through the creation of water drop out (wetted) zones.

Additionally this gives a loss of inhibitor filming, since the increased surface area impacts thedriving forces for slow, fast and spontaneous localized corrosion or passivity. In this regard

inhibition injection may require multiple dosing and monitoring points, to help better quantifytrue efficacy and reliability of the corrosion management programs.

Other comparative work by NACE is underway regarding ICDA (Internal Corrosion Direct Assessment) though that is presently still under review. 8 Although at present the driver for that is mainly onshore pipelines, and so recommendations for deepwater subsea pipelines isstill more dependent on predictive design and minimal inspection criteria, hence the emphasison CA values. As alluded to earlier the corrosion issues when incorporated to any new or existing designs are often hotly contested and strongly debated, frequently not easily resolved.

As a result solutions appear to be best formulated using risk based methods. And for carbonsteels semi quantitative methods using numeric judgments for high, medium, low, risk have

been developed to include better more repeatable revisions as new data are generated

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.These risk based methods are constantly under review to help quantify critical physicalparameters, and corrosion mechanisms for specific design and operating conditions such ashigh water cut developments, non-steady physical/chemical excursions, or bursts of MIC/biofilming (laminar flow phenomena), transported corrosion products and their re-deposition (turbulent flow phenomena), and episodes of sanding (erosive high flows). Theimpact of such upset or non-steady phenomena has also tended to make data base or software driven data management programs a little redundant in many cases since thepredictive trending can become less reliable. To counter that effect a greater reliance on profilereasoning appears better, thus the implication that flow related mechanisms must beinterpreted case by case, and through consensus.

DEVELOPMENT OF CORROSION ALLOWANCE

The best way to determine the optimum CA value can be subjective but it has beenpossible over a number of case studies to develop an acceptable and realistic methodology.This can still be a contentious issue, and the corrosion analyst must therefore take account of all inputs, opinions, and where possible supporting standards, codes and guidelines. Typicallyto allow a defensible CA evaluation, it is normally best to list the main assumptions to avoidlater confusion.

Enabling Assumptions

• Identify the dominant corrosive species usually CO2, with defined or understood water chemistry content.

• Review, verify, and prioritize or assume the dominant flow regime, e.g. single or multiphase flows, stratified, slug, annular flows etc projected through the life cycle. Thiswill require a review of the steady state and non-steady excursions or transient flowsituations. Typically the flow assurance report examines the likely scenarios and istherefore critical to this judgment.

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(alleviate) corrosion. These influencers have impact on all corrosion mechanisms but have aparticular stimulus for flow assisted corrosion mechanisms, for example as follows:

Accelerators influencing flow dynamics; Against bare steel the increased flux of transportedspecies such as CO2, O2, chlorides (break down passivity), and transported iron oxides, etc.

Passivators influencing flow dynamics; Surface condition smoothing, residual inhibition, oilwax films, sulfate/calcite precipitation, pH buffering bicarbonates, TDS such as Langelier or equivalent 1,6,7,8

Impact of Temperature and Flow

Temperature and flow regime are closely linked since CO2 corrosion is dynamic and verysensitive to electro-chemical and physical imbalances (especially fluctuating P,T,V). Generallysteady state (P,T,V,) conditions tend to promote protective film compaction and thereforepassivation, and low corrosion rates. Lower temperatures <120°F (~50°C) tend to promotepatchy corrosion with softer multi-layered iron carbonate (siderite) scales providing some

barrier protection increasing up to ~140-160°F (60-70°C). Above these temperaturesdamaging localized corrosion is observed as films lose stability and spall off giving rise togalvanic ‘mesa’ attack. Though there is evidence of a down turn in the plateau after ~ 80°C for certain cases. In reality the project design basis usually insists on a maximum value for temperature, as it does for other critical parameters such as pressure, materialscharacterization (yield stress, hardness, toughness, etc). Regarding flow, the production ratescan be influenced by flow regimes such as slug flows and annular gas flows. This can provecritical for vertical risers connecting the flowline to the offshore structure or topsides. Thegeometry can act almost like a ‘specification break” whereupon the flow regime shifts largelydue to the increased effects of gravity as the flowline transforms from a horizontal to a verticalmember. The sag bend at the touch down zone (at the interface flowline to riser) can become

a high risk corrosion component warranting greater degree of corrosion control, such as athicker section, increased local CA, internal coating epoxy or TSA, increased monitoringroutines etc.

The leading edge of slugging flows is linked to extreme highly turbulent shear stresses (> 2000Pa) capable of destroying protective inhibitor films. For liquid slugs the phenomena isconsidered related to dissolved gas breakout effects, rather than wave causing forces, thoughmuch research is still underway to try understand slugging flow behavior within multiphasefluids. In a similar manner annular flow regimes can increase the extent of surface wall wettingeven under lower water cut values, thus again reducing oil phase wetting and undermininginhibitor contact to the wall. Annular flows can also pull main flow entrained sand particulates

to the steel, thus damaging passive films at minimum and stimulating physical erosion at worst.Other flow regimes such as mist flows are also important in the context of direct dropletimpingement, but these do appear to be rare in the oil and gas industry.8

Hence it is argued that for process steady states (constant P,T,V,) steady uniform corrosioncan be expected, whereas for unsteady states, transient states and excursions will promotelocalized corrosion, often through the initiation of pitting/crevice activity followed by growth of same during future steady conditions. The impact of inhibitors can be crucial in retaining life

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cycle fitness for purpose. This is largely due to difficulties with mixed inhibitors (also known ascocktailing) performance under variable flow regimes. Here multiple corrosion and scalingmechanisms need to be addressed under many operating flow regimes- laminar, turbulent,stratified, annular, bubble, slug etc. Accelerated non-standard tests can help, but the real proof can only come during field trials, noting that these usually have the greatest leverage. It is also

likely that once flowline localized corrosion sets in, then it is more likely to be self propagating(auto catalytic) and may be less influenced by changes in the bulk conditions; though morework is required in this area.8,20,24

Flowline Corrosion

Whilst most pipelines or flowlines are horizontal, portions of them can be subject to shifts inelevation and undulation, often to the degree that a major impact on corrosion can beintroduced through full water drop out, or intermittent wetting at low lying points. The upwardsections can also be sensitive to water slide back as the effects of gravity come into play 1.The challenge is therefore to ascertain the extent of localized corrosion that could occur, andmore importantly where. This burden is best addressed by historical, track record, and

judgment preferably supported by cross asset field data; inevitably this can only be realisticallydone via the ALARP process. The individual localized corrosion threats can be examined andrisk ratings used to rank up or rank down the corrosion allowance assessment. Typically theratings High, Medium and Low Risk (HR, MR, LR) may be assigned to reflect such predictions.These are usually subjective qualitative interpretations, but can be semi-quantified if enumerated. Most companies now use an ABCDEF etc coding for failure consequences, and a1 to 6 coding for failure probability.8 However, there is a good argument to keep matterssimple with an equivalent 3x3 matrix, without jeopardizing output. Other useful guidelines, andfailure mechanism definitions are also established through the API 580.29

Wettability

Not withstanding the above arguments, the competition between oil and water wetting canfrequently be the deciding factor. Oil wetting is generally inhibitive whereas water wetting is aroot cause of corrosion. The two wetting phenomena have variable resistance to fluid shear,electrochemical, and surface tension properties. The onset of corrosion can be linked to thewater cut anywhere in the range ~1-70%. There are no thresholds but properties such aslight/heavy, API gravity, contaminants, corrosion product stickability, etc. are considered ratecontrolling. This is likely one of the main reasons why laboratory data do not correlate to fielddata. The former has precise definition whereas the latter is prone to much scatter. However itis accepted that field observations will always govern the decision process. For deepwater assets careful conservatism is vital and therefore easier to justify and typically we can argue:

For <2% water cut - Low Risk corrosion

For 2-10% water cut - Medium Risk Corrosion

For >10-40 % water cut -High Risk Corrosion

For >>40% water cut- Very High Risk Corrosion

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These criteria are all very significantly impacted by the actual flow regimes in place. In virtuallyall cases the most susceptible parts will tend to be horizontal positions at six o’clock, close togirth welds, and in the vicinity of flow separation geometries such as Tees and Wyes. Verticalsections such as risers are also impacted in that gravitational effects can come into play asflow regimes transition to different patterns. Flow assurance review therefore becomes an

important consideration, and active corrosion will also affect the surface roughness profile, fluidboundary layer patterns, and extent of emulsification with high water fractions being tolerated if the water remains entrained. Examples of flow modeling graphs taken from various flowassurance scenarios are presented in Figures 2-4. These serve to illustrate how the base linecorrosion rates may be significantly impacted at critical junctures of the flowline routing. Asindicated earlier the most difficult prediction is not so much whether localized corrosion willoccur but more likely the question is invariably where? A close examination of the foreseeableflow regime curves and maximum flow velocities can help assist with that judgment.

For operating profiles examined in this way; such as stratified flow, annular flow, slug flow andbubble flow, it has to be assumed that all flows are in essence turbulent as defined by theaverage flowline Reynolds number, but recognize that within each flow regime there will becomplex inter-facial behavior, including laminar stratification. The extreme corrosive conditionsfor all will be high P, T,V, excursions and dead leg/stagnation due to shutdown or fluidentrapment. The nature of these excursions is not always predictable, however reliable on linemonitoring results will assist mitigation and control, provided it is done at the right place.

Physical Considerations

For steady P, V, T, conditions, corrosion mechanisms may be properly articulated however for extreme conditions and fluctuations there will invariably be an associated burst of additionalenergy/velocity, heat flux, and temperature spiking. These will all tend to destroy surfacepassivating films exposing bare steel to the aggressive CO2 chemistry and galvanic

accelerators such as partial remnants of siderite, magnetite, and possibly sulfides. It is thoughta resumption of standard pressures after such an episodic excursion will tend to re-stabilizeprotective films, but it is important to have an overlap in the increased inhibitor dosage wellbeyond the re-stabilized period (order of days). And it is plausible that in certain cases thelarger localized cells may continue to self propagate if suitably shielded and critical species or nutrients are still made available. The many components or facets of flow assisted corrosionare described, along with closely linked mechanisms.

Flow Assisted Corrosion

Flow assisted corrosion (FAC) is linked to the flow regime and is thus related to flow

assurance. And since there are many ‘what if’ scenarios there are a vast number of variables,and it is important to recognize and control such activity (which may in fact be quite localized)to minimize the risks of damage. Some observations may be described:

(a) The FAC phenomena are often separated from erosion, impingement, and cavitation,and best addressed by the planned suite of in situ corrosion monitoring. Hence givingpredictions and correction by ‘live’ corrosion data over the life cycle.

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(b) Flow regimes are expected to be turbulent, but it is known that dead leg or mini-stagnant zones can exist within the turbulent envelope, leading to accelerated corrosionstimulated by MIC. These mini- areas are found downstream of horizontal flow line girthwelds, at six o’clock in low lying sections, pigging loops, and manifold interfaces.

(c ) If the threat of such localized erosion or significant stagnant pocket corrosion isdetermined to be high or severe (at bends, near welds, etc.) remedial options such asdiscrete internal coatings (TSA, epoxy) may be introduced as solution options.

The impact on CA is medium to high risk (caveat, unless level of disturbance is controllable)

Pre-Corroded Surfaces

As alluded to earlier, pre-corroded surfaces can provide high risk corrosion initiation sites.The parameter is difficult to quantify, as it influences the structure of the laminar sub layer within the hydrodynamic boundary layer, and therefore all manner of general and localizedcorrosion. Essentially what may happen is that bare pre-roughened/pre-corroded steel

surfaces will tend to be more active than smooth (un-corroded) surfaces. These surfacesfrequently stimulate detrimental corrosion especially in the presence of chlorides and biofilms,and this may occur under various stages, typically:

(a) Poor storage conditions, prior to installation.

(b) Improper hydrotest exposures (fluid retention).

(c ) Inadequate protection during commissioning (inadequate or zero chemical inhibition).

(d) Pre-corrosion can also act as an accelerator for flow assurance related scales(waxes/hydrates/sulfates/carbonates, etc.). Scales well anchored in this way willinvariably prove to be harder to remove.

(e) Pre-corrosion must therefore be treated as a critical variable, and suitable steps shall betaken to minimize if not eliminate it.

The Impact on CA is considered Low/Medium Risk depending on preservation levels.

Dead Leg Corrosion Dead leg corrosion is a major threat that can be due to stagnant fluid corrosion as well as

sludge build up and blockage issues. This is a complex area with multiple corrosion

mechanisms at work over the temporary shut in periods. There are many accepted actions,typically:

(a) Ensure that the best practice ( proven) inhibitor (with inbuilt biocide content) is injectedso that long term residual corrosion protection will be attained, and that chemicalpartitioning coefficients will maintain the required dose of inhibitor and biocide at bothtop of line ( TOL) and the bottom of line (BOL).

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(b) The concept of introducing a greater corrosion allowance for such sections can beconsidered, as well as local CRA lining.

(c ) Dead leg sections may deploy internal coatings especially if dead leg will re-enteredinto service. This must cover the internal weldments, as they will be the most vulnerable

areas for accelerated corrosion. However if the line will not be re-used it is reasonableto omit such coatings for economic reasons. Noting that, in certain cases deadlegsections can be open to the flow (strictly not isolated) but still with no flow exchange.

(d) The dead leg section could also be filled with dead crude/diesel as practiced elsewhere(with added oil soluble inhibitors and biocide component). The partial fill condition mustbe avoided, as this could lead to TOL (multi phase gas) related corrosion which will bedifficult to control under the storage conditions envisaged.

(e) Ideally thicker sections should be used and/or the dead leg sections must have adedicated in-built corrosion monitoring plan to allow intervention if serious localizedcorrosion were to occur.

(f) Stagnant dead leg corrosion is dangerous and unpredictable especially if hidden MIC isinvolved. The life cycle threat will therefore be best managed by synergistic multipleactions including internal coating and regular monitoring.

(g) Dead legs may also be subject to suitably planned batch flushing to passivate the leg just before isolation and again before any re-introducing service. Remote Operatedvehicle (ROV) assisted U/T monitoring before any new fluid inventory could be used tore-qualify fitness for purpose.

The impact on CA considered medium risk (if robust chemical programs are planned andused). The key with all inhibitor selections is to ensure that all realistic scenarios are tested or accounted for by representative testing under the mixed chemical formula conditionsanticipated.

Transported Deposit ion Flow Related

Flowline production profiles are subject to change, and whilst the influence on flowassurance can be modeled, the situation is not so clear for the impact of such profiles oncorrosion. The main interest here is to maximize productivity. In practice the multi-phasefluids often influence hydraulic performance, but may or may not be influential regardingimpending localized corrosion which is stimulated by well fluid residues such as waxes,hydrates, asphaltenes, as well as any added chemicals. The following express specific areasof concern:

(a) The wax and hydrates tend to be of most concern in mixed multi phase flows, andspecifically tailored strategies are often developed to manage them. Both are verysensitive to temperature transients (cool down) especially pronounced at deepwater seabed cooling conditions, undulating pipeline topography, and imposed by systemshutdown cycles and pressure changes.

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(b) The evaluations are usually done by flow assurance specialists, using fluid flowmodeling techniques applied to hydrates, waxing and slugging phenomena individually.The link between flow assurance and corrosion is therefore often not made in Industrybecause of poor reproducibility.

(c ) The presence of any deposition whether it be wax, asphaltene hydrates or inorganiccarbonate (calcite) or sulfate scales thermodynamically can and kinetically will lead tolocalized corrosion activity largely by the retention of chloride and or microbe ladenwaters within randomly patchy scales. These scales may be quantified for high water cut regimes by the empirical Langelier Index.20 for scaling (protective) or non-scaling(corrosive) tendency of the waters, allowing chemical dosing adjustments to be made.

It should be noted that whereas wax, scale or corrosion products can take weeks or months tomanifest itself, in contrast hydrate formation (mainly for gas flowlines) can form very quicklyover short periods hrs/days especially immediately downstream of pipe diameter changes (exitto larger wye section), control valves, chokes etc, and therefore can have a greater impact onproductivity and safety especially if hydrate plugging occurs. Additionally scale and waxtreatments tend to be reasonably compatible to corrosion inhibitors, the traditional hydrateinhibitors methanol and glycol can be compatible to corrosion inhibitors when mixed inhibitorsare used, however hydrate inhibitors including the new kinetic hydrate inhibitors (KHI) canexpress some antagonism regarding corrosion inhibitors. In all cases it is vital to demonstratecorrosion control is not jeopardized, using suitably formulated and representative tests andfield trials. Hence flow related deposition analysis will require a considerable amount of reliable water chemistry data during the operations phase, and an accurate determination of real shear stress values at the wall. A diligent combination of all data from the on-line monitorsnamely sand, flow, and water sampling chemistry would therefore be helpful in quantifying andhelping maintain clean corrosion free surfaces through the life cycle. It is fair to say that softer scales are thicker >>5mm but more easily removed, whereas harder scales may be thinner

<5mm but will require more rigorous efforts to remove. The mixed nature of the deposits willlikely decide that parameter and the corrosion product content could therefore be critical.Efficient pigging and chemical formulating (mixing of chemicals often also referred to ascocktailing) to address such wax/hydrate scaling and corrosion are therefore vitalconsiderations to preserve production. In contrast asphaltene deposition is more complex inits interaction with corrosion since the patchy scales can encourage tight crevice corrosion.

Advanced Monitor ing

It is important to realize that flow dominated corrosion phenomena require more advancedcorrosion monitoring techniques. Typically for deep susceptible horizontal portions of the

flowlines the actual location of critical localized corrosion is very difficult and not readilyidentifiable even with pre-determined high risk areas. The location of such corrosion activity isalmost random in nature, basically depending on the ‘chance’ sites of preferred deposition,metallurgical discontinuities, physically sheltered zones, impingement areas, biofilmattachment areas, etc. One of the better ways of utilizing advanced monitoring are themapping techniques such as the Field Signature Method (FSM) unit or equivalent, these givea very good opportunity to evaluate real time localized corrosion and erosion damage. Theunits are fully instrumented spool pieces (typically 3-5 diameters long) permanently inserted

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into the flowline, (ideally must include weld for corrosion evaluation) giving an outstandingopportunity for accurate real time monitoring if placed at the right site 8,14,15. The latter caveat is challenging but do-able. The spool comes with an array of external pins wiredthrough to a monitoring control pod and can arrangement, and data transferred to the controlroom remotely. If used in conjunction with multiple monitoring and sampling (ex topsides

probes/coupons) such mapping can be a powerful integrity verification tool. By using anappropriate interpretation it is possible to predict physical or parametric zones of susceptibilityas summarized in the two case examples described below:

Case History 1 Typical Base Case:Single Well Impact of Operating Profiles on Localized Corrosion

The analysis of profiles against localized corrosion risk propensity arequantified via designated ratings of High, Medium Low Risk (HR, MR,LR) as follows:

Water Cut Profiles HR at years 1, 3, 5, and beyond

Pressure Profiles MR Gas ex-solution-TOL corrosion @ 4-5miles, HR bubble impingement on SCRbend sections.

Temperature Profiles MR @ > 5 mile stagedue to ΔT drop into the uniform corrosionrange.

HR for 1-5 mile, temps ~60-70°C mesathreshold.*

Actual Liquid Veloci tyProfiles

LR within API 14E and industry thresholds40 ft/s for liquids and nil sand but can revert

to HR at >4 miles over years 1, 2, & 3 if sand and corrosion combine. Flowassurance via C-factor selection.

Superficial LiquidVeloci ty Profiles

Flow Assurance variable – impactingFroude analyses and corrosionassessment.

Actual Gas Veloci tyProfiles

HR (>API14E Thresholds). Expect someactivity >5 miles and SCR over first 2 yrs.

Superficial Gas VelocityProfiles

Flow Assurance variable – impactingFroude analyses and corrosion

assessment.

Flow Regime Profiles HR Slug flows dominate, SCR morevulnerable due to additional bubble flows -2phase impingement

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Case History 2:Two well case impact of Operating Profiles on Localized Corrosion

The analysis of profiles against localized corrosion risk propensity maybe quantified via designated ratings of High, Medium Low Risk (HR, MR,

LR) as follows:

Water Cut Profiles HR as for single well case, but mostvulnerable at BOL >3 mile distance for fifth year, due to fluctuating water cutprofiles, likely stimulate MIC.

Pressure Profiles MR Gas ex-solution-TOL corrosion @ 4-5miles, HR bubble impingement SCR bendand vertical.

Temperature Profiles MR @ > 5 mile stage due to ΔT drop(uniform).*

HR 1-5 mile temp values ~ 60-70°C(localized threshold).*

Actual Liquid VelocityProfiles

LR within API 14E and industry thresholds40 ft/s for liquids and nil sand but can revertto HR at >5 miles over first and secondyears, if sand and corrosion combine. Flowassurance via C-factors.

Superficial Liquid VelocityProfiles


Actual Gas VelocityProfiles

HR (> API14E Thresholds). Expect someactivity >4 miles and SCR over first 2years.

Superficial Gas VelocityProfiles


Flow Regime Profiles HR Slug flows dominate, SCR morevulnerable due to bubble flows andfluctuating water cuts predicted after fifthyear **

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In both cases cited above, the temperature profiles* can point to a dangerous false sense of security. The topside probe and coupons will tend to reflect less aggressive lower temperature general corrosion whereas the higher temperatures upstream will tend tosupport localized mesa attack. Thus supporting the argument for a suitable mapping unit tohelp quantify such corrosion disparities. For the case history 2, the steel catenary riser

(SCR) appears vulnerable to bubble impingement**, and to that effect the top 300ft of theSCR could be considered as a large spool for non-intrusive monitoring with advancedtechniques such as guided wave ultrasonic’s. And as caveat, it should be noted that whilstthe API14E criteria and thresholds are well established the erosion guidelines for extremescenarios can be modified with higher more practically oriented C factors if client experiencegoverns. The C factor concepts are sometimes contested, however that might be bestaddressed by the use of well defined Key Performance Indicators (KPI`s), as elucidated in arecent study.30

The example risk assessment taken from the early Cassandra risk module, see Table 3showing corroboration of the corrosion allowance, assumes a corrosion inhibitor efficiency

>95% and operational availability >95%. The optimized C factors (per API 14E) can beselected to reflect practical conditions. The data is illustrative only, with C factor of 100 beingquite a conservative value designed to minimize the effects of erosion-corrosion. In realityhigh C-factors say 100 to 150, even up to 200 can be used per the API-14E guidelines anddepending on operator experience. Supportive correlations from industry can also beusefully deployed as verifiers though there is a tendency to use the above approach as thebase case.8,9,15

Integrated Subsea Systems

Since most new subsea projects in the GOM are almost exclusively in deepwater, the limitsof current technologies can be tested. In order to maintain high levels of productivity with thistrend the need for increased subsea system reliability adds new emphasis to the overall designand operational corrosion management philosophy. The emphasis of linking flow assuranceand corrosion therefore also impacts the reliability discipline such that assessing risks of malfunction need to be identified to maintain production. Typically operators now conduct quiteinvolved reliability studies for subsea production systems in the GOM. These must of necessityinclude all subsea including moving parts, with an in-depth analysis of all system components.The intent of the reliability work is to identify improvements to the design, manufacturing andmaintenance of standard and new or additional equipment to be installed on the platform or thesea floor. As is normally accepted most failures occur during the commissioning/startup stage

or towards the end of life cycle for any given component. This is a result of either improper design or manufacturing or from a “wearing out” effect. This type of behavior is frequentlyillustrated by the typical “Bath Tub” curve shown in Figure 1. The criticality of design, materialsselection, and corrosion assessment for deepwater subsea assets means zero or minimalcorrosion issues are required during the early years, when maximum revenues from productionare needed to offset high CAPEX. As the life cycle proceeds corrosion issues tend to be better manage-able as on stream data (pigging/probes/coupons etc) are generated. The OPEX costsare sometimes minimized and offset by shorter field life’s anticipated. 8,15

15



Given this type of behavior, the maintenance history of similar systems can be analyzed toprovide probability of failure of new or future systems. The information can be used to producea risk model that will predict component and sub component failure rates. Using this model,startup failures can be reduced and inspection intervals recommended to ensure that

components meet benchmarks and are subsequently repaired or replaced prior to failure. Themodel will also have great benefit for older facility life extension studies, whereupon the wear out zone can be significantly extended by good corrosion management.

Upon completion of the reliability study recommendations for failure mitigation and preventionactivities are normally carried out for the duration of the project life cycle. Invariably thisincludes improved maintenance practices to achieve these goals.

INTERNAL CORROSION DIRECT ASSESSMENT

Dangerous internal corrosion and indeed failures have occurred on pipelines carrying gasspecified to be dry.8 The method termed internal corrosion direct assessment (ICDA) has beendeveloped to assess the corrosion impact of short-term upsets on pipeline integrity. Themethod is expected to enhance pipeline integrity, reliability, and public safety. ICDA can beused to enhance the assessment of internal corrosion in gas transmission pipelines and helpensure pipeline integrity. The method is mostly applied to gas transmission lines that normallycarry dry gas but may suffer from short term upsets of wet gas or liquid water (or other electrolyte). The knowledge basis should be readily transferrable to other media fluids.

The basis behind ICDA is that detailed examination of locations along a pipeline where anelectrolyte such as water accumulates provides information about the remaining length and

remaining life condition of the pipeline. If corrosion exists, it will likely be at location(s) of suchliquid water accumulation. Results of multiphase flow modeling can be used to predict thewater condensation, water wetting and the critical angle of inclination that would hold-up water.In addition multiphase flow simulation provides accurate information related to pH, partialpressure of CO2, flow regime, fluid velocity and residence time. Spreadsheets can bedeveloped to show where the critical angle is calculated, given pipe diameter, gas velocity,pressure, and temperature. Typical procedures involve the following steps:

Predict and calculate water hold-up, water wetting and critical angle of inclination.

Identify upstream pipe inclinations, which exceed the critical angle

Inspect upstream locations for corrosion, relate information to downstream corrosion risks

Consider features that might trap water (e.g., Low Spots, Drips, Valves, stagnant legs, etc.)

16



This information will then be used to determine if internal corrosion is likely or unlikely to exist

in a chosen length of pipe. Many studies and practices are presently under review in this

regard. 8

Water Condensation Analysis

One of the key threats identified under special circumstances is the possibility of top of theline corrosion (TOL aka TLC), this almost exclusively depends on the gas content as it pertainsto the flow pattern and much research is being conducted in this area via private initiatives andcommercial JIPs.8 The pertinent rate controlling step is thought to be the water condensationfrom the gas phase, under temperature differentials, usually imposed by rapid cooling. This isoften the case when hot gas dominated production fluids enter the flowline exposed to externalsea water. The subsequent temperature fall stimulates condensation at the upper surfaces of the flowline, leading to sustained wetting. Recent studies have shown that such TOL is a major concern when the water condensation rates exceed 0.15 g/m

2s and the production fluid entry

temperature at the point of sea water cooling exceeds 50 °C.

The area of the flowline (or riser) exposed to this discrete condition is usually small, however, itis safety critical, and so must be subjected to close analysis and if possible close monitoringand inspection help quantify the extent of TOL corrosion. This must be done frequently for theearly life (condensation rates greatest impact), thereafter frequency may be relaxed, as datadictates.

Top of Line Corrosion Analysis

TOL is a dangerous failure mechanism, since the rate of material loss is often very high andlocalized. Once the upper pipe wall is subjected to irregular thinning the mechanical pressurestresses (hoop stresses, and stress concentration at corrosion defects in particular) canprompt failure. The TOL subject matter is being researched by many companies and JIP

studies; however the work is not published openly8. Nevertheless by making certainassumptions and using known material performances it is possible to predict the extent of degradation, and quantify the risk and formulate response actions such as discrete TOLcorrosion inhibition and specific pigging methods.

The top of the line corrosion mechanism is a complex phenomenon, and generating pragmaticremedial actions is difficult but not impossible. 25-28 Figure 5 shows a simplified representationof TOL 26 and the way water vapor containing dissolved CO2 and organic acids (volatile fattyacids such as acetic acid, at low pH < 3), condenses at the top of the line in a typical stratifiedflow regime. The film of condensation at upper regions though dynamic remains in contact withthe steel surfaces, giving highly accelerated corrosion. Under these conditions it is reasonedthe critical rate step is the rate of condensation at the upper wall, and that in turn is a functionof the temperature profile of the pipeline. If the temperature of the wellhead production fluids ishot and rapidly cooled by the external environment (sea water) then, condensation will occur tothe detriment of mechanical integrity. Many ‘what if ' type flow assurance analyses are usuallyneeded to help quantify this risk, using advanced fluid analyses such as OLGA® modeling.The predictive corrosion rates can be based on the predicted temperature profiles and thepublished TOL corrosion correlations for example the Nyborg-Dugstad correlation. 25 There

17



are few published models, standards, or recommended practices, in this area, and thus theavailable equations such (1) can be used on an iterative basis, to determine TOL activity 8,25

Corrosion Rate = 0.004*Rc*Cfe*(12.5-0.09*T) (1)

Where:

Corrosion rate: given in mm/y

Rc: Condensation rate g/m2/s

Cfe: Saturation iron levels in condensation (difficult variable, 50-200 ppm often selected).

T: Temperature deg C

The formula gives a corrosion rate prediction, but is only considered representative of actualdissolution rates if reliable and accurate inputs are used. To that affect a number of ‘what if’scenarios can be tried, as shown for the case history in Table 4. The worst case envisagedleads to a corrosion rate of 0.62 mm/y though less aggressive dissolution rates are alsocalculated. It is also useful to include varying condensation rates. Estimates of the saturated

iron value will also be required, and if it is deemed that a proportion of the riser/flowline issusceptible to the threat of TOL, then design action such as recommendations for a economicCRA lining of the steel pipe sections in question (typically <1000ft), or perhaps enhancedthermal insulation such as GSPU, to shield the heat transfer. Or in extreme cases, bothsolutions may be contemplated.

The design process is an iterative process and any such recommendations will go through thedeliberations of a rigorous design appraisal and design verification. In terms of designing TOLcorrosion control methods, some advanced pigging methods have been successfully deployed,such as the so called 'V-Jet pigging method' which appears to have good promise if parallelfluids and residues are closely analyzed for a continuous feedback loop. The threat level of TOL corrosion can often be best quantified by looking at the materials performance adjacent

reservoirs and assets in the vicinity.

To assist with design verification, it is strongly recommended to have a close synergy betweencorrosion analysis, flow assurance, and corrosion monitoring design. In particular focusing, onthe mechanically high risk portions of the asset, especially over time periods whencondensation rates are expected higher, and the development of a corrosion managementstrategy, with well defined KPIs, as presented recently.30 These can it is thought be easilydefined to cover for targeted corrosion rates, maximum velocities, threshold MIC (bacterial)values through biostud analyses, solution and sand content analyses, flow regimedeterminations and constraints thereof, etc. Hence it is seen that pragmatic solutions can beimplemented even when mechanisms are still being more closely researched.

CONCLUDING REMARKS

Corrosion and its interactions with the flow phenomena is a complex discipline, neither onedominates the other. Corrosion modeling results are often found not to agree with field data.The discrepancy is often blamed on the inadequacy of the models. However this work hasconcluded that the differences are better explained by the rationalization of the effects of flow

18



regime on the base and localized corrosion rates. The project is ongoing with a company ‘go-by’ anticipated in the near future. The core postulate is that the lack of agreement betweencorrosion modeling data and field experience is due more to inadequate account of corrosionstimulating flow regimes, rather than limitations of the modeling; thus reverting the onus for corrosion prediction away from corrosion modeling to the flow regime side. The arguments are

new and ongoing, and a paradigm shift in thinking is needed to explore further the linksbetween corrosion and flow assurance. And under renewed vigor within the industry, andmany new capital green field explorations, this would seem attainable, and it is envisaged thatpredictions made in this area, quantified by the concept of corrosion KPIs, would therefore berelatively quickly benchmarked against real field data in the near future as deep subseaprojects generate useful operations data.

ACKNOWLEDGEMENTS

The authors wish to thank IONIK Consulting-JP KENNY for support in writing this paper, and

the invaluable comments and help from many colleagues in the Industry.

REFERENCES

1. B. Singh, T. Folk, P. Jukes, J. Garcia, W. Perich, D. Van Oostendorp, EngineeringPragmatic Solutions for CO2 Corrosion Problems, paper 07310 NACE Corrosion 2007.

2. S. Olsen, CO2 Corrosion Prediction by Use of Norsok M506 Model- Guidelines andlimitations, paper 03623, NACE Corrosion 2003.

3. R. Nyborg, A. Dugstad, Understanding and Prediction of Mesa Corrosion Attack, paper 03642, NACE Corrosion 2003.

4. B. Singh, T. Folk, P. Jukes. J. Garcia, W. Perrich, Research In Progress Symposium,presentation, 06R206, NACE Corrosion 2006.

5. C. Tang, F. Ayello, J. Cai, S. Nesic, Experimental Study on water wetting and CO2 corrosion in Oil-Water two phase flow, paper 06595, NACE Corrosion 2006.

6. S. Nesjic, J. Cai, K.L. Lee, A Multiphase Flow and Internal Corrosion Prediction Modelfor Mild Steel Pipelines, paper 05556, NACE Corrosion 2005.

7 B. Singh, B. Poblete, G. Smith, J. Britton, Risk, Rust and Reliability,paper 05553, NACE Corrosion 2005.

8. IONIK-J P Kenny Reports, Internal Spreadsheets and Toolboxes 2005-2008.

19



9. Norsok M506 Software and BP Cassandra Software Modeling and Support Literature,2003-2007.

10 B. Hedges, D. Paisley, R. Woollam, The Corrosion Inhibitor Availability Model, paper 00034, NACE Corrosion 2000.

11. I. Rippon, Carbon Steel Pipeline Corrosion Engineering: Life Cycle Approach, paper 01055, NACE Corrosion 2001.

12. B. Hedges, K. Sprague, T, Bieri, H.J. Chen, A Review of Monitoring and InspectionTechniques for CO2 and H2S Corrosion in Oil and Gas Production Facilities: Location,Location, Location! paper 06120, NACE Corrosion 2006.

13. G.A. Dalzell, Inherently Safe Design paper 85698, Society of Petroleum Engineers,Convention, 2004.

14 G. Kelly, IONIK Klips - Internal Reliability and Integrity study Dec 2006.

15. IONIK Consulting- T4B Private Venture Studies- Materials, Corrosion Modeling, andFitness for Service 2005-2007.

16. DNV RP 0501, Erosive Wear in Piping Systems 1999 (updated 2002).

17. API 14E RP, Offshore Piping Design Section 2.5, Version 1991.

18. API 17D Specification for Subsea Wellhead and Christmas Tree Equipment.

19. UK HSE/TUV-NEL Erosion Research Report 115, 2003.

20. L.L. Shreir Corrosion Handbook , Butterworth Heineman, 3rd Ed 1994.

21. DNV offshore Standard-Submarine Pipeline Systems OS-F101, 2000.

22. US DOI-MMS Offshore & Pipeline Regulations - PINC Listings 2005/06.

23. Federal Register –DOI/MMS Proposed Rules - 30 CFR parts 250, 253, 254, and 256,Oct 2007.

24. M.G. Fontana, and Greene, N.D. Corrosion Engineering, McGraw Hill(Orig. pub. 1967, Re-pub ca 2000).

25. R.A. Nyborg, A. Dugstad, TOL Corrosion and Water Condensation Rates in WetGas Pipelines, paper 07555, NACE Corrosion 2007.

26. R. l. Waterhouse, Developments in Spray Pig Inhibitor Application.The Pipeline Pigging and Integrity Management Conference, Houston, Feb., 2008.

20



27. T.R Andersen, A.M.K. Halvorsen, A. Valle, G.P. Kojen, A. Dugstad,The Influence of Condensation Rate and Acetic Concentration on TOL Corrosionin Multiphase Pipelines, paper 07312 NACE Corrosion 2007.

28. F.S. Vitse, S. Nesic, Y. Gunaltun, D.L. de Torreben, P.Duchet-Suchaux, Mechanistic

Model for the Prediction of Top of the Line Corrosion Risk, paper 03633NACE Corrosion 2003 .

29. API 580 Risk-based Inspection, Recommended Practice, First Edition May 2002.

30. B. Singh, Krishnathasan K, Making the Link between Inherently Safe Design,Integrity Management and Pigging. The Pipeline Pigging and IntegrityManagement Conference, Houston, Feb., 2008.

21



Table 1 Localized corrosion tendencies, exemplified by PREN, CCT, and CPT values.

Note: These values are based on empirical formulae, composition, and testing and arevery sensitive to contact electrochemistry. The Alloy elemental compositions and

mechanical properties are available in most suppliers literature. The order of corrosionresistance typically is:

Alloy 625 > SD > DSS ≈ Alloy 825 > 316LSS > 304LSS.

The values are generally thought to be more applicable to static conditions and notsensitive to flow, though in principle if the flow regime can alter the pitting potential thensome sensitivity could be recognized. Hence in principle standard laboratoryassessments should always be supported by non-standard and fully representativetesting and field observations.

ALLOY PRENCCT(°C)

CPT (°C) LOCALIZED CORROSION RISK

304SS 19 < 0 15 High Risk

316SS 25 <0 20 Medium Risk

Al loy 825 33 <5 30 Medium-Low Risk

22 Cr Duplex (DSS) 37 20 30 Medium-Low Risk

25 Cr Super Duplex (SD) 47 35 60 Low Risk

Al loy 625 51 57 77 Low Risk

22



Table 2 Informational Norsok / Cassandra Model comparisons, adapted. 9

Parameter UnitsMax or RangeNorsok/Cassandra

Comments

Temperature °C 5 to 150/30 to150 Impacts creation and

integrity of ironcarbonates. Risk of

localized corrosion

increases >70°C)

Total Pressure Bar 1000/2900 No direct stimulus of electrochemistry per sebut accelerates corrosionrates via acidity/CO2.

Total Mass Flow Kg/m3 Various Per software.

Fugacity of CO2 (Gas) Bar Mole%

0 to 10/0.2 to 0.65Variable

The CO2 partial pressuremust be ≤ total pressure.

Allowed range of mole%function of total pressure.

Wall Shear Stressor Velocity

Pa 1 to 150 Pa /1.5 to13 m/s

Steady <150 Pa definedDisturbed flow(welds/bends/tees) >150Pa not defined.

pH ( NB temp rangevaries)

N/A 3.5 to 6.5 Expected range 4.5-6.

Glycol concentration Wt% 0 to 100 Important but not oftenconsidered

Inhibitor Efficiency % 0 to 100 >95% with a stipulatedaim for 100% availabilitybut target >95%acceptable, calculationsbased on 95%.

Note: The modernapproach is now to focuson achieving the targetcorrosion rate of 0.1mm/y

Note:

The models are strictly only applicable for uniform and localized corrosion issues musttherefore be factored in per experience. The exception is when corrosion rates are veryhigh (say>15mm/y) when it can be argued legitimate to have that self included. Thereare other accelerating or reducing effects some which are identified in the main text.

23



Table 3 Example of Risk Assessment adapted from early Cassandra Risk module. 9

Corroboration of corrosion allowance, assumes corrosion inhibitor efficiency and operationalavailability at >95%. The C factors (per API 14E) selected to reflect practical conditions.

Table 4 Case History-Typical TOL Calculations

Example : Selected ‘What if Inputs’Iteration

CASE1 CASE3CR -mm/y 0.31

CR -mm/y 0.4675

Rc-g/m2/s 0.25 Rc-g/m

2/s 0.25

Cfe-ppm 50

Cfe-ppm 50

T-degC 70 T-degC 35

CASE2 CASE4CR -mm/y 0.62

CR -mm/y 0.4225

Rc-g/m2/s 0.25 Rc-g/m

2/s 0.25

Cfe-ppm 100

Cfe-ppm 50

T-degC 70 T-degC 45

Knowns Knowns Variables

- Uninhibited rate from model Uninhibited corrosion rate = 4 mm/yr Inhibitor Availability = 0.95

- Inhibited rate - assume 0.1 mm/yr Inhibited corrosion rate = 0.1 mm/yr Corrosion Allowance = 5 mm

- Design life - normally fixed Design Life = 15 years

Options Available Options Available / Selected

- Inhibitor availability 0-95% MAXIMUM recommended reliance on corrosi on inhibit ion - Corrosion allowance up to 8 mm INCREASE corrosion allowance up to 8 mm maximum

- Alter design life (if practical)

If Outcome not acceptable, check: Output for Single Phase Systems

- Corrosion allowance < or = 8mm Corrosion allowance required = 4.43 mm

- Inhibitor availability <or =95% Acceptable = Yes

- Corrosion allowance selected > CA required Corrosion Risk Category = 4

This section relates to multiphase fluids Fluid Velocity (Multiphase)

- If singl e phase, enter C=100 C factor = 100

- C factors < or =100 do not affect risk category Comments =No change to Risk Category- C factors 100-135 increase risk category by 1 Final risk category = 4

- C factors > 135 not recommended

Summary Section Summary

'Acceptable' should appear against values for: Uninhibited corrosion rate = 4 mm/year

- Inhibitor availability I nhibited corrosion rate = 0.1 mm/year

- Corrosion allowance Design life = 15 years

- C factor Corrosion al lowance requ ired = 4.43 mm

- Corrosion risk factor

- Overall (reliant on achieving above) Assumed inhibitor availability = 95%

Selected cor rosion al lowance = 5.00 mm

C factor (multiphase) = 100

Corrosion Risk Factor = 4

Overall

Acceptable

Acceptable

Acceptable

Acc eptab le

Cassandra Corrosi on Risk Categories

Select inputs with aim to get acceptable values in output cells.

If acceptable values cannot be achieved with maximum input values, conditions are too corrosive for carbon steel.

Acceptable

Acceptable ?

24



Figure 1 A typical failure distribution or “ Bath Tub” curve for pipelines.

For new green field and deep subsea pipelines and interfield flowlines it is necessary to havebest design options deployed to minimize the probability of corrosion failures during the criticalrevenue producing early life, when maximum or optimized production is required.

25



Figure 2. Empirical representation of liquid hold up as a funct ion of flowline inclination.

This is critical in practice and whilst variations occur, laboratory work as above indicates thatthe sensitive angles are in the range 1-10 degrees, thereafter there appears to be a fall off inholdup tendency.8,15

Flow Loop

experiments

26



27

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

0.20

0 2500 5000 7500 10000 12500 15000 17500 20000 22500 25000 27500

Pipeline Length [m]

W a t e r C o n d e n s a t i o n R a t e [ g / m 2 / s ]

Water Condensation Rate -WHP to PP Water Condensation Rate -WHP to PP - Only Insulated From WHP to Subsea Tee, 0.5in PP

Subsea Tee

Processing Platform

WHP Riser Base

Water Condensation Profil es : WHP to Subsea Tee & Tee to Processing Platform

Note: Flowline is insulated from WHP riser base to Subsea Tee.

Figure 3 Gas pipeline, water condensation from flow modeling showing

relationships between water condensation rate against flowline length andoptimized insulation criteria.

This case history analysis shows how the threshold condensation rate recorded as~0.15 for corrosion activity can be very usefully deployed in establishing the need for well defined limits for external insulation for first ~3000 ft only. 8,15 Thus makingconsiderable savings on manufacture and installation costs for the remaining ~23000 ft.

27



28

Oil Production to 1650/1000/600 psig Arrival, 6" Pipeline, 3" GSPU

Steady State Flow Regime Profi les

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

0 10000 20000 30000 40000 50000 60000

Distance (feet)

F l o w R e g i m e ( - )

5500 BOPD - 8 MMSCFD 8,700 BOPD - 14 MMSCFD 13,000 BOPD - 22 MMSCFD

Flow Regimes Definition s:

1 - Stratified Flow

2 - Annular Flow3 - Slug Flow

4 - Bubble Flow

Wellhead

Riser Top

Figure 4 Oil Line relationships between predicted flow regimes and flowline lengthusing flow modeling techniques.

In this case it can be seen that changes in corrosion mechanism and therefore inhibitor sensitivity need to be addressed for the various flow regimes, namely BOL pitting for stratifiedflows, high leading edge shear and liquid erosion damage for slug flows, condensationcorrosion for the gas/annular flows and bubble impingement for the bubble flows. These areoften categorized in the normal HML risk assessments.8,15

Note- this example as all others is illustrative only and other flow regimes can also beinfluential.

28



Figure 5 Typical Concept TOL Schematic Representation. 26

pragmatic effects of flow on corrosion prediction

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