Paper No.

77

INTERNAL CORROSION MONITORING OF SUBSEA PRODUCTION FLOWLINES - PROBE DESIGN AND TESTING

M. W. Joosten, J. Kolts, P. G. Humble Conoco, Inc.

Ponca City, OK USA

T. J. Blakset D. M. Keilty CorrOcean a.s. Britannia Operators Ltd

Trondheim, Norway London, England

ABSTRACT

This paper addresses one technique for acquiring subsea corrosion rate data. Subsea monitoring provides the advantage of measuring the corrosion inhibitor efficacy at the point of injection, rather than inferring performance from platform measurements. The internal condition of pipelines can be monitored in a variety of ways. The optimum monitoring technique will change with pipeline age, location, accessibility, and operating conditions. More importantly, the applicable methods may change based on the type of information required. For evaluation of corrosion inhibitor performance a high-sensitivity corrosion monitor is required. A prototype dual-element, electric-resistance probe has been evaluated for pressure and temperature stability under simulated Britannia subsea operating conditions. The probe fUnctioned well under all conditions over an extensive test period. As expected, temperature had the greatest impact on the stability of the corrosion measurements. Interpretation of the relative response of the dual probes to the variety of test conditions is useful in evaluating the validity of field data and the tinctionality of the probe.

Issues, revealed by the testing program, included anomalous data points and fluid behind the probe elements. The anomalous data were easily identifiable, but disrupted the automated calculation of the corrosion rate. A loose connection caused the anomalous data points. Ingress of fluid behind the probe element is still a concern for long term exposures.

Keywords: Corrosion Monitoring, Subsea, Electric Resistance Probe, ER Probe, Design, Construction, Testing

Copyright 01998 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be made In writing to NACE International, Conferences Diwsion, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed m the U.S.A.

INTRODUCTION

The Britannia field is situated 210 kilometers north-east of Aberdeen, Scotland, covers approximately 112 square kilometers, and is the largest undeveloped gas-condensate field in the UK North Sea. Recoverable reserves are approximately 3 trillion cubic feet of gas and 145 million barrels of gas condensate. Britannia’s reserves are being developed through a single drilling, production, and accommodation platform at the east end of the reservoir and a subsea well center with 14 slots. The subsea center is located 15 km west of the platform. The platform has 36 well slots and is supported on an eight-leg steel jacket in 140 meters of water.

The Britannia production fluids are corrosive and corrosion inhibitor will be injected into the subsea test and production headers. Corrosion monitoring subsea and on the platform is required to monitor inhibitor performance. Uninhibited corrosion rates for the Britannia subsea system are 10 mm/y. For reasons of economics, the design is based on steel flow lines (one 1Cinch production line and one S-inch test line) protected by a corrosion inhibitor. The flowlines are designed for a 25year life with a 25 mm wall thickness including a 2 mm corrosion allowance. The “allowable” corrosion rate for the flowlines is 0.08 mm/y. The two factors that influence the detection limits are the corrosivity at the monitoring location may be less than the maximum and corrosion rate measurements are not accurate at the detection limit. Accounting for these two factors, a detection sensitivity of 0.018 mm/y for the subsea location and 0.005 mm/y for topside monitoring location is required.

The use of corrosion inhibitors in multiphase gas pipelines has a long history. One of the classic and now historically significant applications is in the Southern North Sea Viking Field.’ A recent re- evaluation of the inhibition effectiveness after 20 years showed the pipeline to be free of corrosion.* While not new, the viability of corrosion inhibition as the preferred corrosion control philosophy for minimally processed fluids, is still being explored.374 While corrosion inhibition is important, it is only a portion of an overall corrosion control philosophy.

Corrosion control philosophy needs to include inspections, intelligent pigging5, corrosion monitoring, corrosion data management systems, operational conditions, sampling, data interpretation and most importantly a feedback loop to operations. The combination of all corrosion related information with the operational details provides the data package required for corrosion risk management. Ensuring reliability and utilization of this information to minimize inspection and maintenance costs is the longer term objective.6

Vital requirements for subsea corrosion monitoring are resolution, practicality, reliability, and accuracy.’ The methods showing sufficient resolution to measure the design corrosion rate are weight loss coupons, electrical resistance, polarization resistance, iron counts, and electrochemical noise. Subsea weight loss coupons are not practical and require retrieval. Polarization resistance and electrochemical noise are unproven in subsea service. Iron counts monitor the integrated corrosion rate over the entire flowline. The most versatile method for sweet production systems is electrical resistance measurements.* Electrical resistance (ER) probes have the required resolution and can be configured for subsea use through adaptation of existing sand monitoring equipment. The ER probe technology has a large experience base, which generates confidence in data interpretation and reliability. However, ER probes have limited surface area and the results can depend on placement and data interpretation. This paper

7712

The subsea ER probes are flush mounted at the 6 o’clock position in the outlet of the stainless steel test and production headers. The probes are positioned within the stainless steel header piping but as close as possible to the stainless steel to steel material transition where the flowlines attach to the headers.

Figure 1 is a schematic of the subsea manifold header. Figure 2 is a photo of the probe installed on a

\ Production header. The probes are located at the highest temperature and but not the highest corrosion risk area based on a CO2 corrosion

reviews ER probe performance under simulated subsea environmental conditions and compares the measured corrosion rates with other monitoring systems.

SUBSEA ER PROBE LOCATION

\ prediction model9 The highest risk Corrosion

Connector for Individual area is further downstream were the Future Tii In Well Tie Ins Monitoring

Probe temperature drops to 75 C. This

Figure 1 Subsea Manifold Header location is within the bundle inside the carrier pipe and not readily

The probe could be placed downstream of the corrosion inhibitor injection point between the manifold and the flowline carrier pipe. The preferred location is within the manifold for the following reasons. The maximum cable length for RS232 communication is approximately 50 meters (low baudrate, no common mode voltage). The tow head to the subsea control system may approach that length. Longer cables must be changed to an RS485 format. Monitoring is best accomplished with the probe in the bottom of a horizontal section of the line. Water will till the fitting. Corrosion can occur in this deadleg at the fitting. A duplex access fitting on a duplex pipe will prevent this type of attack. Mounting the probes in the header

I

accessible. . .

Figure 2 Subsea ER probe positioned in the header

eliminated additional duplex pipe work, minimized the cable length, and protected them during installation.

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PROBE DESIGN AND CONSTRUCTION

The ER probe design for the subsea installation is a dual element probe with one 0.150 mm Width - 4 mm thick element and one 0.500 mm thick element. Figure 3 is a schematic of the probe elements. Each of the sensing elements has been given an optimal geometry Length

with respect to metal loss 17mm

resolution and accuracy. The probe element was machined from flowline pipe material, the same material as the topsides probes. The chemical composition is Thickness

shown in Table 1. This monitoring system is an adaptation of standard subsea sand monitoring

Figure 3 Schematic of the subsea ER probe

equipment. The data collection frequency is set to a 30-minute interval. The probe is mounted in a dual containment system. Probe seal failure would not result in any leakage to the sea. The thin element probe has been used previously for a topside inhibitor evaluation program and is standard for sand monitors.”

Table 1 Chemical Composition of the X-65 Subsea Flowlines

C Is IP Ibfn ICr INi IMo ICu 1 Si Iv 1 Al INb 1 Ti I N

0.120 IO.002 IO.016 Il.36 IO.15 IO.08 IO.03 IO.16 IO.32 IO.040 IO.030 IO.005 1 0.005 1 0.009

The dual element design satisfies two diverse tunctions of the corrosion monitoring system. First, the monitoring system must be able to detect upsets where the corrosion inhibitor is not protecting the line due to supply interruptions, ineffective mixing, changes in flow regime, etc. One upset per year, if not detected, consumes the corrosion allowance in 3 days. Satisfying this first function of the corrosion monitoring system requires a highly sensitive probe with a short response time, i.e. able to detect a corrosion rate of 0.08 mm/y in 3 days. Commercial ER probe resolution is 111000 parts. The subsea ER probe resolution is l/2000 parts, minimum. Based on this resolution, the 0.150 mm ER probe element will detect a corrosion rate of 0.08 mm/y in less than 24 hours. A meaningtul measurement can be achieved in 2 days.

The second function of the monitoring system is to measure the corrosion inhibitor effectiveness. The anticipated corrosion rates are less than 0.025 mm/y, based on laboratory tests and field correlations. While the thinner probe element, in the subsea ER probe design, would detect these corrosion rates, the life of the thinner element is limited to 3-5 years. As the field ages and water rates change there is a need to monitor inhibitor effectiveness over a longer duration. The thicker probe element (0.500 mm) will

7714

have a life of 10 years at the design corrosion rate and be capable of detecting the 0.025 mmfy corrosion rate in 7 days. Inhibitor optimization or new inhibitor trials would require three weeks (3X the detection limit). Note that the relationship between element thickness and resistance becomes non-linear once the metal loss exceeds half the element thickness. The text will reference element thickness of 0.250 and 0.075 mm, which is half of the actual element thickness.

The duplex stainless steels probe bodies are designed for 400 bar at 125 C. The probe fits into a standard 2-inch access fitting. For subsea use, a secondary containment system is incorporated to prevent leakage in case of probe failure. The probe element is electrically isolated from the pipe to eliminate galvanic couples.

The resistance/temperature reference element is located directly behind the two sensing elements. This location is chosen to obtain the best possible temperature compensation. It is very important that the sensing elements and the reference element are at exactly the same temperature. With the chosen design, the static temperature difference is very low. The dynamic temperature difference (temperature transients) is larger and causes the probe to give erratic readings as long as the temperature is fluctuating.

The probes were constructed under the IS0 9001 Quality Plan. In addition to the normal quality assurance program the probes have been subject to a 20-day test, under pressure (200 bar) to expose problems in the potting processes. Resistance measurements of each element were taken before the test, 1 day after the start of the test and on day 20, these were recorded and showed no significant change.

EXPERIMENTAL PROGRAM

The subsea probe test program was to determine the probe stability under various simulated operating conditions.

1.

2.

3.

4.

Variations in pressure and temperature in an inhibited environment

containing COZ. Variations in pressure and temperature in an inhibited environment containing CO* and low levels of H$% Corrosion rate comparisons with other monitoring systems in an uninhibited environment containing co*.

Corrosion rate comparisons with other monitoring systems in

Temperature . Galvanic Probe

ER- Probe

Figure 4 Turbine Pump Flow Loop

an uninhibited environment containing COz and HzS.

Loop Pressure

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The prototype subsea electrical resistance probe was evaluated in a turbine pump flow loop. The tests were performed in an environment consisting of 20% Britannia condensate and 80% distilled water with 0.5% NaCl. A schematic of the flow loop and associated instrumentation is shown in Figure 4. The flow loop is constructed from corrosion resistant alloys (titanium and 316 stainless steel). A turbine pump flows the liquid at designated velocities through 13 mm tubing at the pump outlet and 25 mm tubing at the pump inlet. The autoclave serves as the reservoir for the pumped fluids. All sections of the test loop are at the designated temperature. The corrosion monitoring methods included weight loss coupon, electrical resistance probe (‘) linear polarization resistance, in-line electric resistance probe’*‘, , electrochemical noise, pH measurements, and iron counts.

A variety of flowing conditions are experienced by the various monitoring systems. The corrosion coupons and a commercial electrical resistance probe were exposed in the autoclave section. These experience a gently moving liquid, probably less than 0.1 m/s. The subsea ER probe is located in the pump inlet. The probe is mounted in a 50 mm pipe spool that attaches to the 25 mm pump inlet line. The ID of the spool is 48 mm. The pump inlet experiences flow about 0.25 fraction of the outlet (13 mm) tubing, based on the respective cross sectional areas. The spool experiences flow about 0.05 fraction of the 13 mm tubing. However, the probe holder is not quite flush in the fixture, and some flow disruption is generated by the enclosure. The in-line electric resistance probe and linear polarization resistance probes are located in the 13 mm tubing. The pipe wall itself is used as the probe element for both of these monitoring systems. The in-line electric resistance probe output is equivalent to an electrical resistance probe when all of the pin pairs are averaged to obtain a single value. A summary of the loop flow velocities is found in Table 2. The velocities referred in the text are indicative of flow in this section of the flow loop. Nominal flow loop velocity is 4 rnlsec.

Table 2 Nominal Flow Velocities for the Various Monitoring Devices

Location 13 mm Tubing 25 mm Tubing

50 mm pipe Spr -’

Flow Velocity, m/set Flow Fraction Monitoring Device(s) 4 1 LPR, In-line ER 1 0.25 None

n-3 n nr o--L--- ER x)1 , “.L I U.“, I J”OStX

I Autoclave stagnant 0 ER, Weigl ht Loss 1

A typical test consists of placing the corrosion coupons and probes into the loop, purging the autoclave and piping with nitrogen, and adding deaerated Britannia condensate and inhibited aqueous solution into the autoclave. The autoclave is pressurized to the desired partial pressure of CO*. The pressure, temperature and flow velocity is maintained by computerized control. The system is then brought to the operating pressure with nitrogen gas. The system is permitted to stabilize at the flow conditions for the test.

The test temperature and pressure simulate the Britannia flowline operating conditions, i.e. 100 C and 95 bar. The pressure and temperature variations were modeled after data from Caister-Murdoch System pipeline inlet for January and June 1995. The typical variations are 10 bar and 10 C. This range was the testing target.

’ Rohrback-Cosasco, Tube Loop Element, 8 mil(200 microns) thickness. * CorrOcean as., Field Signature Method, Clamp-on.

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The CO2 and H2S levels matched the Britannia CO2 partial pressure (2.2 mol%) and the H2S content (15 ppm). Initially, inhibitor at 100 ppm was used. This was increased to 200 ppm. Later, another inhibitor was added, when the first inhibitor proved ineffective. The inhibitors were used in combination with Britannia condensate to produce an environment similar to that expected in the flowlines. In addition to the Britannia subsea probe, weight loss coupons, a commercial electrical resistance probe, LPR, and in-line electric resistance probe data were recorded for comparison,

The temperature was varied by changing the temperature controller cycle time from 15 seconds to 240 seconds. The temperature fluctuated f 10 C. Since the autoclave was closed, there was an associated pressure cycling.

Next the pressure was fluctuated independently of the temperature. The pressure was varied by providing an intentional leak from the autoclave through a micrometer valve. Once the pressure reached a set point, the automatic controller increased the pressure to a level above the prior set point, and automatically closed the nitrogen gas inlet. The slow intentional leak again permitted the pressure to drop, cycling the pressure.

The flow rate was then reduced and monitoring continued. At this point, the gas pressure was dropped, and the system was purged with CO2 and HzS containing gas. The partial pressure of the CO* was maintained at 6 bar and the HzS pressure was charged to 3 mbar. The temperature was varied under conditions giving a high corrosion rate, in an environment containing CO:! and at low partial pressure of HIS.

The turbine pump was adjusted to reduce the liquid velocity in the flow loop and monitoring continued. At the low flow rate, the temperature was cycled again. Further pressure cycling was not carried out since pressure cycling had no impact on the resistance probe outputs. Varying temperature had the primary effect on the probe outputs.

An addition of 200 ppm of the second inhibitor brought the corrosion rate to a low level, and temperature fluctuations could be monitored at the low corrosion rate. After the temperature fluctuations were completed, the system was purged of acid gases and shut down.

RESULTS

The subsea ER probe data and the data from the other monitoring techniques are contrasted with major changes in the test conditions. The corrosion data is given in two forms, the raw form of accumulated metal loss and as a corrosion rate. The raw subsea probe data is converted to corrosion rates by using a moving average calculation. A moving average is calculated over a pre-selected time period. The average uses the difference in the metal loss data over the given time step. The resulting corrosion rate is in units of millimeters per year (mm/y). The longer the time averaging step the smoother the resulting data plot. However, lengthening the time averaging step requires additional data points to calculate a corrosion rate.

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Data Anomalies

Subsea ER probe data was taken for two days prior to filling the loop with liquid. The probe took data in air, with the wax coating still in place. The wax protects the probe element from corrosion prior to being placed into service. The wax was then removed with a heat gun and solvents and the probe placed into the dry flow loop. Metal loss data for this time period is shown in Figure 5. The data shows a low residual background noise, but

. .

Metal Loss, microns Metal Loss, microns

100 100

30 30

10 10

3 3

I I

0.3 0.3

250 250 micra micra

0.1 ' I I I 0 0.5 1 1.5 2

Time, Days Figure 5 Air Exposure, Room Temperatu t-e, 20 C

with two large output anomalies. These output anomalies continued throughout the test period with a higher frequency at the end of the testing. In total 10 output anomalies were recorded. Inclusion of the anomalies in the processed data gives erroneously high

Metal ~~~~~ microns

corrosion rates. These data 20 were easily identifiable (Figure 5), but totally i 0 disrupted the automated computer interpretation of 5 the corrosion rate. All such data were confined to readings from the 150 micron element.

A spare Interface Unit (PIU) showed no anomalies after more than 100,000 data points (100 0.2 times the original data set). 3.5 The problem appears to have been in the PIU

4 4.5 5 Time, Days

Figure 6 Effect of CO2 Addition on Day3.8.90 C.20% Britannia Condensate electronics and not within 0.5% NaCI, 100 ppm Inhibitor, Flow Rate 4 mkec

the probe. “Burn-in” test periods, used for the equipment going subsea, detect these types of electronic problems.

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Pressure and Temperature Fluctuations

Next, the 100~ was leak tested and charged with

~&d LOSS, microns

COZ. Upon introduction 30 of the CO*, the metal loss increased quickly (the slope of the metal loss curve is the corrosion 20 rate) and then leveled off, Figure 6. Note that the commercial ER probe

Temp C 120

110

100

was located in the 10 relatively stagnant fluid in 90 the autoclave reservoir. This probe measured very low metal loss. The LPR 0 probe was located in the 7 7.5 8 8.5 9 9.5 108’ flow stream and showed lime, Days metal loss between the Figure 7 Temperature Effects on Corrosion Monitors, 200 ppm inhibitor

subsea ER probe and the 20% Britannia Condensate, 0.5% NaCl, Flow Rate 4 mkec

commercial (stagnant fluid) probe. The ER and the LPR corrosion rates did not reach the low levels anticipated. While unexpected, the opportunity to examine the probe under corroding conditions was seized and a series of pressure and temperature fluctuations were started. The temperature was fluctuated between 90-105 C. Figure 7 shows the effect on the metal loss measurements when the temperature is fluctuated. The data scatter related to temperature can be seen in both ER probes.

Temperature fluctuations are expected and compensated for in the probe design. Even with the temperature scatter the corrosion data trend shown in Figures 7 is still clearly obvious. The data processing methodology effectively dampens the temperature- induced fluctuations. Figure 8 is an example of the processed data for the 75 micron and 250 micron elements as a function of temperature variations.

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It 1s not possible to Metal ~~~~~ microns fluctuate the temuerature in Pressure, bar a pressurized system without 50 some fluctuation of the pressure. However, it was 4o possible to fluctuate the pressure at a constant temperature. As shown in 30 Figure 9, the changes in __.II.,...,..... - - . ..-.. __

commercial resistance probes or the LPR stability.

Effects of Velocity Time, Days

High rates of metal Figure 9 Effect of Pressure on Metal Loss, 200ppm Inhibitor

loss were detected by the 20% Condensate, 0.5% NaCI. Flow4 mkec, 100 C

subsea ER probe, as compared to the commercial electrical resistance probe located in the static liquid in the autoclave. This led to the supposition that turbulence at the ER probe head location, relative to the flow stream, was causing the high metal loss rates. The n/ktti Loss, IIIiCrOtIS Flow Rate mls flow rate was decreased several times during the testing to 1.3rnkec. The metal loss from the ER probe, the LPR and the commercial probe were all unchanged, Figure 10.

75 micron 5

. . . . ___j............... ..,. . . . . . . . . . . . . . . . . . . . . .._......_..._.__. ^ ,.,......,__.._,.....”

Y v 250 micron

I+

4

10 .__________. ~~~~~~.~.~~~~~~ -. _,_,.,,,, ~ . . . . . . . . . -

LPR L--- low -

Probe Response to H$ Additions

On Day 13, the loop was purged of all CO* and a combination of H#/CO2 gas r L was added to the autoclave.

10.6 10.8 11 11.2 11.4 11.6 11.8 12-

No liquids were removed or lime, Days added. The concentrations of Figure 10 Effect of Flow Rate at a Constant Temperature and Pressure

H#ZOZ were chosen to 20% Condensate, 0.5% NaCl, 200 ppm Inhibitor. 100 C, 96 bar

produce 15 ppm HzS and 2.2 mol% CO2 in the autoclave gas when pressurized to 95 bar. The metal loss data shows a surge, but begins to level off within one half day, resuming the upward sloping trend observed prior to the addition

77110

of the H$S/CO2 mixture, Figure Il. On Day 17 the autoclave was de- pressurized and reloaded with fresh H&CO2 mixture. Both times the HzS/COZ mixture was added resulted in similar changes in the rate of metal loss. ER probes are susceptible to erroneous readings (weight gain) in the presence of H2S due to the formation of conductive and adherent sulfide scales. At 15 ppm H$ this effect was not observed.

Comparison of Various Monitors

Metal Loss, microns 50

40

Pressure, bar

100

30

20

10

Figure 1 I Influence of H2S/C02 Addition, 200ppm Inhibitor 20% Condensate, 0.5% NaCI. Flow4 mkec, 100 C

The two ER probe elements can be compared if the respective sensitivities are compensated for by using longer averaging times for the thicker element. Figure 8 shows a comparison using a lo-hour average for the 75micron element, and a 24-hour average for the 250 micron element. The corrosion

rates track extremely well, with the thinner element being more sensitive to environmental changes. Low alarm levels can be set for the thin element output and high alarm levels can be tied to the thicker element output.

Figure 12 is a comparison of the averaged corrosion rates for the commercial ER probe and the 75 micron ER element. The lower corrosion rates recorded by the commercial probe can be attributed to several factors, i.e. the inhibitor effectiveness under flowing/turbulent conditions, the different probe element materials, and differences in oil/water fraction, It is

77111

interesting to observe the correlation at the end of the test when the corrosion rates are low. After adding the second inhibitor, corrosion rates for both probes were quite low.

Figure 13 shows a comparison of the corrosion rates for the LPR and the ER ’ probe. The correlation is quite good, in spite of the very ’ different principles of operation of these two probes. f’

Weight Loss Coupons 6,

f Weight loss coupons U 1

consisted of 5LX52 pipeline ~ coupons in the autoclave and

,

short sections of carbon steel .1 tubing, in-line with the flow stream. The short sections of i! f E f B $ $ t

carbon steel tubing could be Flprv 13 Cmlpul~n.fcamhn~Cr~ LPRslnd 7s mklvm mpnbe

cnmkmm-1shur*vat*)

removed and replaced without disrupting the test. A new section of tubing was inserted each time the test conditions were changed. The 5LX52 coupon was removed at the end of each test series. The differences in the flow rates between the two coupon sites did not allow comparison. However, comparison between the monitoring systems and the coupons yield good correlations. In one instance, the LPR results

were between 0.050-0.075 mm/y and the steel tubing measured 0.08 mm/y. Both measurements are taken in the t%ll fluid flow. For general comparison a photograph of the ER probe elements is shown in Figure 14. The probe elements are quite pitted and appear to be corroded through along at least one edge on each element.

In-Line ER Probe Figure 14 Photograph of the subsea ER probe elements after

testing

In-line ER probe data was collected through out the testing period. This in-line probe is a sophisticated multiple electrical resistance probe. Contact is made with a short section of flow loop tubing through a clam shell arrangement of contact pins. It was effected by temperature changes in much

77/l 2

the same way as the other electrical resistance probes. The tubing weight loss gave a corrosion rate of 0.38 mm/y. The high weight loss of the in-line tube confirmed the results of the other monitoring methods. All other monitoring methods gave higher corrosion rates in the flowing loop as compared to the static autoclave.

Protectiveness and Removal of Temporary Wax Coating

A low melting point wax (55 C) protected the prototype probes from in-transit corrosion. The probe elements were coated with this wax to prevent the thin elements from corrosion prior to the startup of production. The probes will be exposed to moist air during shipping, handling and installation, The hydrotest water will also be corrosive. Even small amounts of corrosion shorten the effective life of the thin element probes. Two issues were investigated. First, is the wax a good protective barrier? Second, will the wax be completely removed by the Britannia condensate when the temperature exceeds 55 C? A test series was run using commercial tube loop element ER probes. One probe was coated with the wax. The wax was aged for 24 hours in an oven at 40 C to simulate the period of time between application and use. Two environments were examined; aerated tap water at 20 C to represent the hydrotest water and 90% Britannia condensate with 0.5% NaCl in water saturated with CO2 at 65 C. The corrosion rate in the tap water approached 0.25 mm/y while the wax covered probe remained at approximately zero. After the fluids were changed and the temperature increased the corrosion rates for both probes increased indicating complete removal of the wax.

The temporary wax coating was a laboratory success, but failed in the field. The low temperatures encountered at the fabrication site embrittled the wax and with even careful handling the wax coating broke off. A grease, that was soluble in the Britannia condensate, was applied.

Supplemental Tests on Additional Corrosion Inhibitors

Additional sensitivity studies” were conducted over the range of conditions under which the probe and inhibitor were expected to operate. The conditions include a range of temperatures, salinity and CO2 and H2.S partial pressures. The probe fUnctioned well under this wide range of operating parameters.

DISCUSSION

In general, the ER probe performed well, it is an effective corrosion monitoring tool for subsea determinations of corrosion rates. It performed well in both sweet and slightly sour environments. The environmental flow conditions vary in the flow loop, and since fluid flow is an important variable in controlling corrosion rates, all monitoring methods in the loop are not expected to provide the same rate. These variations notwithstanding, the trends in monitoring with the ER probe were consistent with expectations among the different locations. The highest corrosion rates were found in the dynamic conditions (in-line ER, LPR, ER) and the lowest in static (autoclave) conditions (commercial ER, corrosion coupons).

The probes were exposed to severely corrosive conditions during the test. After the test, the probe elements were visually examined. Figure 14 is a photograph (after cleaning) of one of the probes. The probe elements were severely corroded, demonstrating regions of complete metal perforation, confirming qualitatively the probe performance.

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Temperature Fluctuations

The subsea ER probe, as is any electrical resistance probe, is sensitive to temperature fluctuations, The best corrosion rates are obtained during periods of temperature stability. The errors introduced by temperature fluctuations exceed the sensitivity of the measurement. Improving instrument precision will not improve the quality of the measurement. This was expected for the subsea ER probe. The operator or corrosion specialist should acknowledge this factor in interpretation, The data scatter from temperature fluctuations effectively reduces the sensitivity of the measurement. If additional information such as temperature, pressure, and flow rate are available in conjunction with the ER probe data, then data interpretation is improved and increased accuracy is possible.

Data Relevance Indication from Probe Noise Spikes

Useful information can be acquired during temperature variations in the system. Comparison of the spike depths between the two probe elements such as shown in Figure 7 is a good measure of the relative element response. The spike depth is directly related to the element sensitivity as shown in Figure 15. In operations, changes in the spike depth ratio would be indicative of an element malfunction. This similarity can be used during actual operation to determine the relevance of the probe output.

Probe Mechanical Integrity

Predicted

10

8

6

4

2

0 0 2 4 6 8 10

Actual Figure 15 Temperature Induced Spike Depth Comparison

for 75 Micron Element Multiplied by Element Thickness Ratio

The potting compound separated from the probe element during this evaluation. Figure 14 shows fluid that has come out from the metal to potting compound interface. This did not create a measurement problem, since the probe performance compared well to other measurement techniques. In environments that cause crevice corrosion, this may result in shorter probe life because of localized attack. Other ER

probe manufacturers use glass to seal corrosion probe elements. Additional testing would be required to quality such a sealing system.

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CONCLUSIONS

Pressure fluctuations, a wide range of operating parameters, and low levels of H2S do not affect ER probe stability. Temperature fluctuations had the most dramatic effect on the ER probe readings, Comparison of the outputs from the dual element ER probe can be used as a data quality control tool. The corrosion rates of different corrosion monitoring devices compared well if the flowing conditions were similar. The highest corrosion rates were found in the dynamic conditions (in-line ER, LPR, ER) and the lowest in static (autoclave) conditions (commercial ER, corrosion coupons). Probe mechanical integrity performance can be improved.

ACKNOWLEDGMENTS

The authors would like to thank the Britannia Co-Ventures; Conoco (UK) Limited, Chevron UK Limited, Philips Petroleum C. UK Limited, Saga Petroleum UK Limited, Texaco North Sea UK Limited, and Union Texas Britannia Limited for their support and permission to publish this paper.

77115

REFERENCES

’ W. R. King and F. R. Taylor, “Field Evaluation of Corrosion Control Chemicals in the Viking Gas Field”, SPE No. 5286, 1975.

* I. Frazer, M. W. Joosten, E. Buck, J. Kolts, G. Jones, “Evaluations, Inspections Reveal North Sea Pipeline Free of Corrosion”, April 6, 1992, O&GJ, p. 5 I-54.

3 E. Buck, J. Kolts, M. Achour, “Corrosion Inhibitor Selection Philosophies for Major Projects”, UK CORROSION 92, October 13-15, 1992, Vol. 2.

4 M. W. Joosten, E. Buck, J. Kolts, D. Erickson, M. Mai, “Monitoring and Control of Corrosion in Offshore, Wet Gas-Condensate Pipelines”, CORROSION/92, Paper No. 9, (Houston, TX: NACE International, 1992).

J. Labrujere, “Intelligent Pigging - An Operator’s View” Offshore Pipeline Technology Conference, February 1-2, 1989, Amsterdam.

L. Harms, “Offshore Oil Gathering Pipelines - How Much Maintenance Can You Afford”, Corrosion Middle East International Symposium & Trade Exhibition on Corrosion Control & Management, NACE- UAE Section, Sept. 16-17,1997, Dubai, UAE.

’ I. J. Rippon, M. W. Joosten, M. M. Salama, D. Smallwood, C. A. Belmear, and H. Horn, Field “Evaluation of Novel Erosion/Corrosion Monitoring Equipment”, CORROSION/94, Paper No. 94002, (Houston, TX: NACE International, 1994).

M. W. Joosten, K. P. Fischer, R. Strommen, K. C. Lunden, “Internal Corrosion Monitoring of Subsea Oil & Gas Production Equipment”, Materials Performance, April 1995, Vol. 34, No. 4, p. 44-48.

’ C. de Waard, U. Lotz, and A. Dugstad, “Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model”, CORROSION/95, Paper No. 95 128, (Houston, TX: NACE International, 1995).

lo B. Ridd, R. Johnsen, D. Queen, “Field Trails Using a New Generation of Electrical Resistance Probe for the Optimization of Chemical Corrosion Inhibitors”, EUROCORR/97, Vol. 1, p. 189- 193.

” J. Kolts, M. W. Joosten, P. G. Humble, J. Clapham, “Aspects of Corrosion Inhibitor Selection at Elevated Temperatures”, CORROSION/98, Paper No. 98037, (Houston, TX: NACE International, 1998).

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Corrosion Inhibitor Injector

Production

\

Connector for Future Tie In

Individual Well Tie Ins

Corrosion Monitoring Probe

Figure 1 Subsea Manifold Header

Fiaure 2 One subsea ER txobe Dositioned in the header

77/l 7

Width - 4 mm

Length 17mm

Thickness

Figure 3 Schematic of the subsea ER probe

Temperature Galvanic Probe

- Loop Pressure

\ -

Noise, Flow Coupon, I, DD J

In-Line kR L’ ”

t I, ic

Aooling - m Coil Doppler

m---- Flow Meter

I

- Turbine

B

Flow Meter

hurbine Pump

Figure 4 Turbine Pump Flow Loop

77/l 8

Metal Loss, microns

30

Temp C

120

100

10 90

0 80 7 7.5 8 8.5 9 9.5 10

Time, Days Figure 7 Temperature Effects on Corrosion Monitors, 200 ppm Inhibitor

20% Britannia Condensate, 0.5% NaCl, Flow Rate 4 mkec

Figure 8 Effect of temperature variations on the 75 and 250 micron subsea ER probe.

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Metal Loss, microns Pressure, bar

. .._ ...... ............ -_I__-

.,..,~~.........._.._II - -. . .................. .-. .-

-- .___._.___ ................. -

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

O.‘! I.. ,..,... . . . . %.. ..,,., . . . ..., “,.,. .,.., ,....... ,..,. .::.. .*.../.... . . . . . . . . . . . . . . . . ...\ I . . . . .

10.2 Time, Days

Figure 9 Effect of Pressure on Metal Loss, 200ppm Inhibitor

20% Condensate, 0.5% NaCl, Flow 4 mkec. 100 C

Metal Loss, microns Flow Rate mls 50

30 . . . . . . . . . I .__. . . _ . . . . ..________.......~......~.. .

I 250 micron c

__..____..___.._.... .., c_ . , . . . 2oP---

1 $. .+ 10.6 10.8 11 11.2 11.4 11.6 11.8 12'

lime, Days Figure 10 Effect of Flow Rate at a Constant Temperature and Pressure

20% Condensate, 0.5% NaCI, 200 ppm Inhibitor, 100 C, 95 bar

l-low +

5

4

3

2

1

b 100

50

iI0

75 micron

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Metal Loss, microns Pressure, bar

Pressure-

TCme, Days Figure 11 Influence of H2S/C02 Addition, 200ppm Inhibitor

20% Condensate, 0.5% NaCI, Flow4 mkec, 100 C

Figure 12 Comparison of the 100 micron commercial and the 75 micron subsea ER probes (75 micron - 10 hour average, 100 micron - 24 hour average).

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Figure 13 Comparison of the corrosion rates for the LPR and the 75 micron ER probe (75 micron - 10 hour average).

4

L 3 t

f2 Ql

0

Figure 14 Comparison of 75 micron ER and LPR (76 micron 10 hour average)

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Predicted

-0 2 4 6 8 IO Actual

Figure 15 Temperature induced spike depth comparison for 75 micron element multiplied by element thickness ratio.

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