Regular Article PHYSICAL CHEMISTRY RESEARCH Iranian .
Regular ArticlePHYSICALCHEMISTRYRESEARCHPublished by theIranian Chemical . Chem. Res., Vol. 6, No. 1, 193-207, March 2018DOI: 10.22036/pcr.2017.93963.1403Beyond the Limitations of API RP-14E Erosional Velocity -A Field Study for GasCondensate WellsM.A. Ariana, F. Esmaeilzadeh* and D. MowlaDepartment of Chemical and Petroleum Engineering, School of Chemical and PetroleumEngineering, Enhanced Oil and Gas Recovery Institute, Advanced Research Group for GasCondensate Recovery, Shiraz University, Shiraz, Iran, 7134851154(Received 30 July 2017, Accepted 25 October 2017)Fluid velocity has the potential to cause severe erosion damage to oil and gas production infrastructure. Therefore, erosional velocitygoverns allowable production rates from existing oil and gas wells. In order to avoid or alleviate damage due to erosion, the AmericanPetroleum Institute Recommended Practice (API RP-14E) recommends a threshold fluid velocity for production tubing and pipelines. Thisstandard utilizes an empirical formula from which erosional velocity can be calculated. However, field and laboratory data have proven thatthe applied empirical constant, known as C-factor, within the formula is not valid for all conditions. In many cases, according to the APIRP-14E standard, erosional velocity is significantly underestimated or overestimated due to insufficient consideration of fluidcharacteristics. In addition, accurate field data on erosional velocity can assist proper pipe sizing calculations for prospective oilfieldprojects. Oversizing of tubing unnecessarily increases construction costs whilst underestimating the required size of tubular can lead tocatastrophic erosion/corrosion failures. In this study, new values for erosional velocity constant, beyond those suggested by API RP-14E,are proposed based on the experimental data achieved from the sidestream pilot test units. The experimental pilot test units were installedon four different gas condensate production fields in the south of Iran. Electrical resistance (ER) probes were employed to gather onlineerosion-corrosion data from the pilot units, each of which was in service for about nine months. The results showed that higher C-factorscan be safely applied for these gas condensate fields in comparison with those recommended by API RP-14E. Furthermore, it was revealedthat the pilot test units exposed to a higher condensate gas ratio (CGR) experienced a greater rate of erosion.Keywords: Erosional velocity, API RP-14E, Erosion rate, ER probe, Erosion/corrosion, CGRINTRODUCTIONDemand for natural gas as a cheaper fossil fuel energysource is rising worldwide. Natural gas has gradually takenover the traditional position of crude oil as the key energysource [1,2]. Consequently, gas producers are seeking eithernew reserves or enhancing rates of production from existingwells. There two major issues and related questionsassociated with increasing the production rate from existinggas wells:1-Productivity index. Can the well produce hydrocarbon at*Corresponding author. E-mail: esmaeil@shirazu.ac.irhigher rates?2-Erosion velocity. Can the production tubing withstand thehigher erosion/corrosion imposed by higher fluid velocity?The first concern refers to the well/reservoir characteristicswhile the second depends on the material properties of theproduction tubing. Normally downhole components of gaswells are more vulnerable to erosion damage than oil wellsdue to the higher encountered fluid velocity. If the answersto the aforementioned questions are “yes” then a higherproduction rate is achievable without having to drill newwells. That is translated into the tremendous savings in costsassociated with drilling, operation, and maintenance of newwells. However, higher flow rate equals higher velocity.
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.This can lead to a considerable degradation of materialsused to fabricate the production infrastructure, especially ifthe fluid contains entrained particulates and/or liquiddroplets. Erosion is a mechanical process caused by flowingfluids. It is defined as the removal of materials from solidsurfaces by repeated impingement of solid particles and/orliquid droplets. Erosional destruction is more obvious andsevere at higher velocities. However, in real conditions,such as oil production, erosion and corrosion impacts aresynergistic [3,4]. A long list of different types of corrosionhas been identified in the oil industry [5-8]. Corrosivecomponents such as CO2 and/or H2S dissolved in producedhydrocarbons initiate corrosion reactions that can beaccelerated by erosion exposing bare material in contactwith the fluid, making the metal even more vulnerable toerosion. If the processes are not considered as occurringsimultaneously, it is not possible to demonstrate whichphenomenon, erosion or corrosion, occurs first. However, itis widely accepted that in oilfield conditionserosion/corrosion phenomena take place [9].API RP-14E Eq. (1) proposes an empirical correlation todetermine the erosional velocity below which erosion and/orerosion/corrosion is not expected [10]:Ve C laboratory experiences have shown that the recommendedvalues of these C-factors are conservative or not dependentupon the system condition. Thus, modification of the Cfactors based on individual fluid characteristics can beperformed. Furthermore, erosional velocity greatlyinfluences tubing sizing in the design stage. Oversizing oftubing unnecessarily increases construction costs whilstunderestimating the required size of tubular can lead tocatastrophic erosion/corrosion failures.PREVIOUS STUDIES ON THE ACCURACYOF API RP-14EHere, a brief summary of the previous studies on theaccuracy of API RP-14E is discussed. Salama [12] reviewedworks of some previous researchers on C-factors and statedthat the API RP-14E limitation on the C-factor can be veryconservative for clean services and is not applicable forconditions where corrosive components or sand are present.He proposed a C-factor of 450 for water injection systemswith solid free and non-corrosive conditions and C-valuesup to 250 for corrosive conditions. Russell et al. [13]reviewed erosion in pipes and stated that API RP-14E Cfactors of 100 to 200 are too conservative for productionand injection tubing associated with wells and downholevalves. Jordan [14] investigated erosion rate in multiphaseproduction of oil and gas. He presented examples ofdifferent values for C-factors used by some oil companiesand concluded that API RP-14E criteria for calculatinglimiting velocity are inadequate. In some cases, thesecriteria give a false sense of security and in other cases itunnecessarily limits production. Ericson [15] reported thatoperators in the North Sea used a C-value of 726 for gascondensate wells and C-values up to 300 for water injectionwells. Esmaeilzadeh [16] studied the feasibility ofincreasing C-factor for South Pars gas field and presented aC-factor of 175 as a justified erosional velocity constant.Mansoori et al. [17] studied the possibility of increasing theC-factor for a gas field in southern Iran. Their resultsshowed that C-factors in the range of 149-195 can be usedfor wells at the point of their initial design. Arabnejad et al.[18,19] presented a method based on the experimental datato calculate erosion rate due to liquid impact for oil and gaspipelines. They verified the model by comparing their(1)where Ve is the maximum allowable velocity (erosionalvelocity), ρ is the gas/liquid mixture density at flowingpressure and temperature and C is an empirical constant.Gas/liquid mixture density can be calculated by Equation(2) [11]: 12409 S l P 2 .7 RS g P(2)198 .7 P RTZwhere P: pressure (psi), T: temperature ( R), Sl: liquiddensity, Sg: gas density, R: gas to liquid ratio (cubic foot perbarrel) and Z: gas compressibility factor.This standard suggests values of C 100 for continuousservice and C 125 for intermittent service while theflowing fluid is solid free. If solid particles are present, Cshould be substantially reduced. Although this equation hasbeen extensively used in the petroleum industry, field and194
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.predicted results with the experimental data in the literature.The results showed that the API RP-14E predictions do notfollow the trend of calculated values from their model.Zahedi, et al., [20] used the experimental data and the CFDcalculations to predict liquid film thickness and flowcharacteristics in the annular flow regime. The simulatedresults of the liquid film thickness trends were in agreementwith the experimental data in the literature. They stated thaterosion rate in elbows is highly dependent on the liquid filmthickness. Parsi, et al., [21] studied the effects of sandparticle size and superficial gas velocity on the erosion ofelbows in vertical slug/churn flow regimes; their resultsshowed that churn flow is a very erosive flow regime. Theyalso claimed that increasing the particle size and superficialgas velocity would increase the erosion rate.Corrosion specimens provide a quantitative determination ofcorrosion rates and offer a visual insight of the corrosiontype occurring within the system under observation. The ERprobes measure erosion/corrosion rate based on an increasein the electrical resistance over time due to loss of material.The ER probes are considered as an online monitoringtechnique since gathering data from them does not requireinterruption of the system. The electrical resistance of aconductive material such as a metal or alloy element isexpressed by Eq. (3):R rLA(3)where R is the electrical resistance, L is the element length,A is the cross-section area and r is the specific resistance.According to Eq. (3) for a specified alloy at a constanttemperature, the ER of the specimen increases as the crosssectional area decreases. ER probes are known as a reliabletool to acquire online erosion/corrosion data.Four unique sidestream pilot test units (2″ internaldiameter) were designed and constructed to determineoptimum erosion velocity by acquiring erosion/corrosiondata in wellhead conditions. These pilot units were capableof handling high pressure and temperature existing at thestudied gas fields. A schematic view of the sidestream pilottest units is shown in Fig. 1. The pilot units were mountedon the main 6″ ID flowline at the wellhead. The upstreamside of each pilot unit was connected to a convenient pointprior to the choke valve and the downstream side connectedto a lower pressure point somewhere after the wellheadchoke valve. The pressure difference between the inlet andoutlet ensures that the fluid stream flows through the pilottest units. The length of the pilot units varies from 8 to 10meters, depending upon the physical characteristics of eachwellhead. The following components and instruments wereinstalled on each pilot test unit:1-Two ball valves to isolate the test units from the mainflowline2-Globe valve to control the flow3-Orifice flange/plate and flowmeter to measure flowrate4-Pressure and temperature gauges4-ER probes for online measurement of erosion/corrosiondataMotivationPossible failures in downhole equipment is a nightmarefor operators due to the difficulties of accessing the failedparts and the extreme costs of repair or replacement. That iswhy operators prefer not to produce at risky conditions(higher C-values) unless they are convinced thaterosion/corrosion is not a problem at higher fluid velocities.However, operating with lower C-values confines wellproductivity and loss of income. There are significantdiscrepancies in the literature regarding optimal C-values(reported from 100 up to 800). Most previous studies havebeen performed with synthetic fluids (mixtures of air, waterand/or sand) in the laboratory at moderate temperatures andpressures. Indeed, the test of duration for previous studieswas relatively short. These conditions cannot represent realoilfield conditions. Moreover, the effect of CGR onerosion/corrosion phenomena has been ignored. This studyaims to bridge the existing gap of reliable C-factors in APIRP-14E in oilfield conditions. To achieve this, a uniquesidestream apparatus has been designed to beaccommodated for use in four gas production fields(Varavy, Kangan, Shanoul, and Tabnak) located in southernIran.EXPERIMENTAL WORKCorrosion specimens and ER probes are widely used inthe oil industry as corrosion monitoring techniques.195
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Fig. 1. Schematic view of sidestream pilot unit for determination of erosion/corrosion rate.Fig. 2. A view of sidestream pilot unit installed on Kangan gas field.196
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Table 1. Production Data and Fluid Properties of the Studied FieldsField nameVaravyKanganShanoulTabnakCGR 98Gas specific gravity0.6400.6550.6610.6901111PropertyWater vapor content (bbl./mmscf)Table 2. Fluid Composition of the Studied FieldsField 27000.0028790.0023820.003900n C4H100.0032000.0041690.0030770.005100i C5H120.0017000.0020850.0016880.002600n 0.001300C110.0003000.0002980.0019850.000800C12 001.0000001.000000Composition(mole fraction)197
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.It is important to mention that the pilot units underwentall the necessary inspections including radiographic tests forthe welded sections and hydrostatic tests. After beingscrutinized by the inspection division of Zagros OilCompany, the operator, the pilot units received approval forinstallation on the high pressure and temperature wellheads.As shown in Fig. 1, gas flows through the pilot unit andafter contacting the sensitive surface of ER probe, returns tothe main flowline. An actual photograph taken from one ofthe pilot units installed in the Kangan gas field is shown inFig. 2.At the time of the experiments, all the selected fieldswere producing sweet gas (without H2S) below their dewpoints. During the experiment, no significant signs of thepresence of solid particles in the production fluid wereobserved both in the sidestream components and in the mainproduction facilities. Since the production fluid is solid-freeand its corrosive components are negligible (H2S 0 andCO2 0.02-mole percent), it is safe to assume that erosionis more dominant than corrosion in these fields. Indeed,high flow velocity inside the sidestream pilot test unitsensures that material degradation due to erosion phenomena,such as liquid impingement and shear stress, are dominantover corrosion. Tables 1 and 2 show production data and thefluid composition of the studied gas fields, respectively.Fluid composition influences the density, and thus C-factorin the empirical equation proposed by API RP-14E Eq. (1).Indeed, corrosive components of the fluid (CO2 in thestudied field) trigger corrosion reactions.Experiments were performed at different flow rates.Since the internal diameter of the sidestream pilots (2″ ID)was much smaller than the main flowline (6″ ID), it waspossible to develop higher velocities through the pilot unitsin comparison with the main flowlines. On each gas field,one well with the highest productivity index was selected toundergo an erosion/corrosion experiment for about ninemonths. Over the course of experiments, erosion/corrosiondata was periodically accumulated by the ER probe byemploying a portable data logger made by CormonCompany. The flow meter and globe valve facilitatereaching and controlling the desired flow velocities passingthrough the pilot test units.The production tubing has a vertical position inside thewells. However, due to operational limitations, verticalinstallation of pilot units was impractical. Therefore, theywere horizontally mounted on the main flowlines.Theoretical simulation of flow regimes by the Pipesyssoftware package (v2.4.73.0) revealed that an annular mistflow regime would develop within the pilots for bothvertical and horizontal orientations. Therefore, horizontalinstallation of sidestream pilots would not cast doubt on thevalidity of the acquired data. A brief summary of flowsimulations for the Kangan field for horizontal and verticalpositions of the pilot unit are represented in Tables 3 and 4,respectively. The performed simulations are in agreementwith findings reported by Boriyantoro and Adewumi [22].They stated that for gas condensate systems, while theamount of condensate is relatively small, the gas ReynoldsNumber is high and the flow regime for horizontal pipes isexpected to be annular mist or stratified flow. In annularmist flow, a thin film of liquid forms around the pipe wall[23].Each of the nominated gas fields inherits an individualCGR based on their reservoir characteristics ranged from3.92-14.07 bbl/MMscf (Table 1). As stated above, the mainpurpose of this study is to evaluate the effect of CGR on Cvalues. To achieve this goal, pilot units were exposed todifferent flow rates and CGRs. Therefore, the installed ERprobes experienced different flow velocities over the courseof nine-month experiments. The average production rate ofthe wells in the studied fields was 62 million standard cubicfeet per day (MMscfd). This rate is high enough to createextreme velocities in the experimental pilot units and causeserosion/corrosion damage to the surface of the ER probes.Temperature and pressure vary from 55 C to 80 C and 90bar to 200 bar, respectively. Temperature and pressureaffect CGR and fluid density calculations. CGR and densityinfluence erosion rate. Moreover, temperature acceleratesthe kinetics of possible corrosion reactions [24].When gas travels from downhole to the wellhead,condensate drops out of the gas stream due to changes intemperatures and pressures associated with operationalconditions. In all flow regimes in horizontal pipes, exceptannular mist, the liquid tends to move to the lower parts ofthe pipes so erosion in such locations is postulated to behigher. In the annular mist flow regime, an annular ring ofliquid forms around the pipe wall while the gas flows as acontinuous phase through the center of the tube [25].198
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Table 3. PIPESYS Flow Simulation for Horizontal Sidestream Pilot Test Unit-Kangan Gas FieldCase Name: Vertical sidestream pilot-KanganCalgary, Alberta CAUnit Set: EuroSINeotecPIPESYSv2.4.73.0Date/Time: Thu Feb 04 14:07:18 2016Pressure temperature 90.862.81FittingPipe89.8589.614.44Tem perature(C)54.96DeltaP(bar)0.14DeltaT(C)-0.04Pipe #154.6854.611.000.24-0.27Fitting #1-0.07Pipe #2LabelFluid transport 2.8576.157700.8080.015Gas density Liquid density(kg m-3)(kg m-3)LiquidGas viscosity(cP)SurfaceVsg(m s-1)Vsl(m s-1)Flow patterntension(dyne cm-1)0.29028.7750.091Annular Mist16.8180.29029.1330.093Annular Mist16.7740.29029.1710.093Annular Mist16.770viscosity(cP)Table 4. PIPESYS Flow Simulation for Vertical Sidestream Pilot Test Unit-Kangan Gas FieldCase Name: Vertical sidestream pilot-KanganCalgary, Alberta CANeotecPIPESYSv2.4.73.0Unit Set: EuroSIDate/Time: Thu Feb 04 14:07:18 2016Pressure temperature summaryPipeline (C)54.950.14-0.05Pipe #154.6854.601.000.24-0.27-0.08Fitting #1Pipe #2LabelFluid transport propertiesCum.InsideLengthdiameter(m)1.91Gas density(kg m-3)Liquid density(kg m-3)Gas uidSurfaceVsg(m s-1)Vsl(m s-1)Flow patterntension(dyne cm -1)0.29028.7740.091Annular Mist16.8170.29029.1310.093Annular Mist16.7740.29029.1690.093Annular Mist16.769viscosity(cP)
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Table 5. Different Flow Rates and the Corresponding C-factor and Erosion Rate-Varavy FieldFluid flow rate(lb h-1)Equivalent C-factorAverage erosion 052182301.051.321.481.68Table 6. Different Flow Rates and the Corresponding C-factor and Erosion Rate-Kangan FieldFluid flow rate(lb h-1)18,19320,64122,04224,43226,000Equivalent C-factor141160176195209Average erosion rate(mpy)0.840.940.981.031.1Table 7. Different Flow Rates and the Corresponding C-factor and Erosion Rate-Shanoul FieldFluid flow rate(lb h-1)Equivalent C-factorAverage erosion ,72834,2402112351.621.825Table 8. Different Flow Rates and the Corresponding C-factor and Erosion Rate-Tabnak FieldFluid flow rate(lb h-1)18,63420,76822,53126,00033,802Equivalent C-factorAverage erosion rate(mpy)1321471591922340.871.181.311.62.2200
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Therefore, erosion/corrosion due to liquid droplets inannular mist flow is expected to be uniform on the pipewall. Consequently, installing ER probes on top of thesidestream pilot units is reasonable for this particular flowcondition and is expected to provide almost the same resultas if the installation is at the bottom.specific data for all fields. Different fields are associatedwith different C-factors although they experienced the sameflow rate of 26,000 lb h-1. This is related to the fact that eachfield has a different fluid density which influences Cfactors. Another important point from Table 9 is that CGRhas a significant effect on erosion rate. For the same flowrate, Tabnak field has the highest erosion rate which can beattributed to its higher CGR. On the other hand, the lowesterosion rate is associated to Varay fields with the lowestCGR. Although CGR has an impact on fluid density throughEq. (2) and thus C-factor, its influence on erosion rate ismore dominant due to higher shear stress on pipe walland/or more chance for liquid impingements.The allowable metal loss for hydrocarbon productionfacilities is 1 mpy according to the NACE RP0775-99standard [26]. Considering 1 mpy as the allowable erosionrate, the corresponding C-factor can be calculated based onthe data presented in Tables 5-8. The calculation ofoptimum C-factor for these fields is shown in Figs. 3-6.Indeed, Table 10 shows the obtained C-factors for all thestudied field conditions based on NACE RP0775-99 andtheir deviation from what API RP-14E has proposed. For allof the studied fields, a value of C-factor equal to 100 hadbeen considered to determine the erosional velocity by theoperator. The results of this study show that the C-factor of100 is extremely conservative and production tubing is ableto withstand higher erosion velocities without risk of failure.Table 10 shows that the Varavy gas field obtained themaximum C-factor with a value of 193 (93% higher thanAPI RP-14E) and that C-factor for Tabnak gas field cannotbe higher than 138 (38% higher than API RP-14E) for a safeproduction schedule. These modified empirical C-factorscan be used to determine erosional velocity and they may bevalid for other gas fields worldwide, considering thecharacteristics of the produced fluid. Moreover, acomparison between C-factors form previous studies andthis research is shown in Table 11.RESULTS AND DISCUSSIONErosion data was gathered from the ER probes atdifferent flow rates and CGR. When exposing them to anew operational condition, the pilot test units are kept inservice long enough (usually one month) to ensure thesystem is in a stable condition and the data can beduplicated. Total exposure time for each field was aroundnine months and the overall degree of data reproducibilitywas over 90 % for all fields.Erosion rate was calculated according to Eq. (4) for eachpilot unit at different operational conditions:Erosion rate ( MPY ) X 2 X1K365 days t1000year(4)WhereX1 is instrument reading at time t1X2 is instrument reading at time t2 t is time elapsed (days) between X1 and X2K is a constant which depends on the probe characteristics;K 10 for the current probesThe average erosion rate (mils per year) at different flowrates (pounds per hour) along with the equivalent calculatedC-factor for each field are shown in Tables 5-8. Theequivalent C-factor is calculated by Eq. (5):C V* (5)In the above equation, V is the actual fluid velocity throughthe experimental pilot units.According to Tables 5-8, the erosion rate is proportionalto the flow rate in the four studied fields; an increase in theflow rate resulted in a growth of the average erosion rate. Inorder to characterize the effect of CGR on C-factor and theaverage erosion rate, all fields underwent an identical flowrate (26,000 lb h-1) for one month. Table 9 shows these% Deviation Optimum Cfactor- Standard CfactorStandard Cfactor(6)The effect of CGR on C-factor is also evaluated based onthe overall data from all the studied fields. Figure 7illustrates how C-factor has responded to CGR variation in201
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Table 9. Effect of CGR on C-factor and Erosion RateEquivalentErosion rate(bbl h 1.6014.07Field nameFlow rate-1CGRFig. 3. Erosion rate vs. C-factor; determination of optimum C-factor for Varavy gas field.Fig. 4. Erosion rate vs. C-factor; determination of optimum C-factor for Kangan gas field.202
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Fig. 5. Erosion rate vs. C-factor; determination of optimum C-factor for Shanoul gas field.Fig. 6. Erosion rate vs. C-factor; determination of optimum C-factor for Tabnak gas field.Table 10. Optimum C-factors for the Studied Gas Fields Based on NACE RP0775-99 CriterionOptimumC-factorDeviation form API RP-14E recommendation for cleancontinues services (C-factor 38%Field Name203
Ariana et al./Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.Table 11. Comparison Between Measured C-factor by Various ResearchersResearcher(s)Standard C-FactorMeasured C-factorDeviation(%)100450350100250150Gas condensate100726626Water injectionwells100300200Esmaeilzadeh[16]Gas field10017575Mansoori, et al.,[17]Gas field100149-19549-95This studyGas field100138-19338-93Salama [12]Ericson [15]SystemWater injectionsystems withsolid freeWater injectionsystems withsolid freeFig. 7. Effect of CGR on C-factor-based on the overall data from all fields.204
Beyond the Limitations of API RP-14E Erosional Velocity/Phys. Chem. Res., Vol. 6, No. 1, 193-207, March 2018.RECOMMENDATIONWORKSthe experimental conditions. The correlation expressed inFig. 7 can be used in any identical gas condensate fieldswhile the dominant regime is annular mist flow with a CGRrange between 4 and 14 and sand-free system. Based on Fig.7, a higher CGR results in lower C-factor due to increasingerosion rate. Therefore, the erosional velocity is a realconcern for those wells with high CGR even when sand-FORFUTUREIt is suggested that the above tests are performed on thegas condensate reservoirs with CGRs and pressuresdifferent than those tested in this study. In addition, theeffect of sour gas can also be considered. Moreover, fortesting the effect of shear stress on the pipe wall due toliquid impingements, it is suggested using a fixed fluidcomposition with different fractions of liquid in laboratoryor in the field.free.CONCLUSIONS1-Unique experimental sidestream pilot test units weredesigned, constructed and installed on four Iranian gasABBREVIATIONScondensate fields to acquire erosion data in productionconditions. These pilot units were capable of handling highpressure and temperature existing at the studied gas fields.Indeed, high flow velocity inside the sidestream pilot testunits ensures that material degradation due to erosionphenomena, such as liquid impingement and shear stress,MPYMils per yearCGRCondensate gas ratioERElectricalresistanceMMscmdMillion standard cubicmeter per dayNOMENCLATURESare dominant over corrosion.2-New empirical C-factors were obtained based on realfield data. These values are much higher than what API RP14E recommended for clean services. The results of thisstudy shows that the C-factor of 100 is extremelyconservative and production tubing is able to withstandhigher erosion velocities without risk of failure.3-Among the studied gas fields, the Varavy field had themaximum C-factor with a value of 193 (93% higher than thevalue suggested by API RP-14E) and C-factor for Tabnakgas field cannot be higher than 138 (38% higher than APIRP-14E) for a safe production schedule. These modifiedempirical C-factors can be used to determine erosionvelocity and can be applicable for any gas condensate fieldswith similar characteristics to those of the studied fields.4-CGR had a prominent impact on the erosion rate due to ahigher chance of liquid impingements and higher shearstress on the pipe wall. A simple empirical correlation wasproposed that relates CGR to C-factor based on the overalldata acquired from the studied fields. This correlation canbe valid for any
OF API RP-14E Here, a brief summary of the previous studies on the accuracy of API RP-14E is discussed. Salama [12] reviewed works of some previous researchers on C-factors and stated that the API RP-14E limitation on the C-factor can be very conservative for clean services and is not applicable for
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