SABP-A-036

Best Practice SABP-A-036

4 December 2011 2011

Corrosion Monitoring Best Practice Document Responsibility: Responsibility: Materials and Corrosion Control Standards Committee

Saudi Aramco DeskTop Standards Table of Contents

1 Scope and Purpose.................... Purpose.......... ................... ................... .......... 2 2 Conflicts and Deviations............... Deviations..... .................... ................. ....... 2 3 References.................................................... 2 4 Definitions and Abbreviations............... Abbreviations.... .................... ......... 2 5 Corrosion Monitoring Techniques............. Techniques..... ............. ..... 3 5.1 Microcor System …………………………. 3 5.2 ClampOn System……………………….. 9 5.3 High Temperature UT Sensors 11 5.4 GUL Permanently Installed Monitoring Sensors (GPIMS )…………. 14 5.5 High Precision Corrosion Monitoring (HPCM) Sensors ………….. 19 5.6 Corrosion Coupon ……………………… 21 5.7 Chemical Analysis ……………………… 30 Appendix

Appendix A – DA-950035-001 ………………..… 38 Appendix B – Corrosion Coupon Report …..….. 39 Best Practice Team

Mohammed F. Al-Barout, Team leader Mohammed F. Al-Subaie Mansour A. Al-Zamil Bander F. Al-Daajani Nayef M. Al-Anazi Ali X. Minachi Minachi Previous Issue: New

CSD / CTU CSD / CTU CSD / CTU R&DC/AMG R&DC/AMG ID/ITU

Next Planned Update: TBD Page 1 of 40

Primary contact: Barout, Mohammed Fahad on 966-3-8809578 Copyright©Saudi Aramco 2011. All rights reserved.

Document Responsibility: Materials and Corrosion Control Standards Committee SABP-A-036 Issue Date: 4 December 2011 Next Planned Update: TBD Corrosion Monitoring Best Practice

1

Scope and Purpose This Saudi Aramco Corrosion Monitoring Best Practice (SACMBP) describes approved Corrosion Monitoring techniques implemented in Saudi Aramco that will improve the integrity and control corrosion in the upstream and downstream facilities. Each corrosion monitoring technique has advantages and disadvantages and Subject Matter Expert (SME) must be consulted for specific use. It is based on current industry experiences and recent corrosion monitoring techniques validated by an inter-departmental and multidisciplinary team of En gineering Services.

2

Conflicts and Deviations If there is a conflict between this Best Practice and other standards and specifications, please contact the Coordinator of ME&CCD/CSD.

3

References 3.1

Saudi Aramco Documents

Saudi Aramco Engineering Procedures and Standards Saudi Aramco Engineering Encyclopedia Saudi Aramco Materials System Specification 01-SAMSS-023

Intrusive Online Corrosion Monitoring

R&DC MICROCOR Assessment Assessment Report Evaluation of MICROCOR™ Probes for On-Line Corrosion Monitoring; MICROCOR™ Probes (Final Report: A220-03/97) 3.2

Industry Codes and Standards

C HEVRON

Guidelines for Internal Corrosion Monitoring of Oil and Gas

NACE STD RP0775-2005 RP0775-2005 Preparation, Preparation, Install Installation, ation, Analysi Analysis, s, and Interpret Interpretation ation of Corrosion Coupons in Oilfield Operations NACE RP0173

4

Collection and Identification of Corrosion Products

Definitions and Abbreviations NACE

The National Association of Corrosion Engineers

CO2

Carbon Dioxide Page 2 of 40


1

Scope and Purpose This Saudi Aramco Corrosion Monitoring Best Practice (SACMBP) describes approved Corrosion Monitoring techniques implemented in Saudi Aramco that will improve the integrity and control corrosion in the upstream and downstream facilities. Each corrosion monitoring technique has advantages and disadvantages and Subject Matter Expert (SME) must be consulted for specific use. It is based on current industry experiences and recent corrosion monitoring techniques validated by an inter-departmental and multidisciplinary team of En gineering Services.

2

Conflicts and Deviations If there is a conflict between this Best Practice and other standards and specifications, please contact the Coordinator of ME&CCD/CSD.

3

References 3.1

Saudi Aramco Documents

Saudi Aramco Engineering Procedures and Standards Saudi Aramco Engineering Encyclopedia Saudi Aramco Materials System Specification 01-SAMSS-023

Intrusive Online Corrosion Monitoring

R&DC MICROCOR Assessment Assessment Report Evaluation of MICROCOR™ Probes for On-Line Corrosion Monitoring; MICROCOR™ Probes (Final Report: A220-03/97) 3.2

Industry Codes and Standards

C HEVRON

Guidelines for Internal Corrosion Monitoring of Oil and Gas

NACE STD RP0775-2005 RP0775-2005 Preparation, Preparation, Install Installation, ation, Analysi Analysis, s, and Interpret Interpretation ation of Corrosion Coupons in Oilfield Operations NACE RP0173

4

Collection and Identification of Corrosion Products

Definitions and Abbreviations NACE

The National Association of Corrosion Engineers

CO2

Carbon Dioxide Page 2 of 40


CS

Carbon Steel

H2S

Hydrogen Sulfide

MPY

Mils per Year

OSI

On Stream Inspection

SCC

Stress Corrosion Cracking

SS

Stainless Steel

TML

Thickness Measurement Location

UT

Ultrasonic Testing

MST

Multi sensors technology

LPR

Linear Polarization Resistance

EIS

Electrochemical Impedance Spectroscopy

ER

Electrical Resistance

HTUT

High Temperature UT Monitoring Sensors

Corrosion Monitoring End Device: The component of a corrosion monitoring system that actually monitors the corrosion while exposed to the process environment. Corrosion probes and corrosion coupons are ex amples of end devices. For this specification only probes will be considered. Electrical Resistance (ER): a measure of the degree to which an object opposes an electric current through it. it. The SI unit of electrical electrical resistance is the ohm

5

Corrosion Monitoring Techniques Corrosion monitoring techniques classified classified as intrusive intrusive and non- intrusive. Intrusive probe is one that penetrates the pressure boundary of the pipework, vessel, or process such as Microcor system system in paragraphs 5.1 and and 5.6. For non- intrusive, it will measure the wall thickness externally. (see paragraphs 5.2 - 5.5) 5.1

Microcor System 

Background

Improvements in corrosion monitoring methods have kept pace with the rapid advances in engineering and science. The MICROCOR™ corrosion MICROCOR™ corrosion monitoring technology was developed in 1995. It has undergone significant improvement over the last 10 years to address serious shortcomings of conventional techniques such as Electrochemical Impedance Spectroscopy (EIS), Electrical Resistance (ER), and Linear Polarization Resistance (LPR) measurements. The MICROCOR™ system MICROCOR™ system is designed to measure corrosion rate or metal loss in all corrosive fluids, including discontinuous electrolytes and intermittent insulators such as oil/water emulsions and wet Page 3 of 40


gases. Having a measurement resolution resolution of 0.00005%, it can establish establish a quantitative corrosion rates trend within a few hours, even at corrosion rates of less than 2-mpy. Consequently, it matches the speed of the LPR method, while providing absolute rather than relative data, without restriction on the nature of the corrosive environment. It also matches the environmental versatility of the electrical resistance technique, but generates data 100-200 times faster than the ER method. The principle of the MICROCOR™ measurement MICROCOR™ measurement is based fundamentally on measurement of inductive inductive resistance. It measures the changes in inductive resistance of a coil embedded within the metal/alloy sensing element or probe as the mass of the sensing element decreases due to corrosion. The sensing element, having a high hi gh magnetic permeability, greatly intensifies the magnetic field surrounding the coil, which in turn causes considerable magnification of the inductive resistance resistance of the coil. Inductive resistance equivalent to 1-5 ohms can be developed in such a sensor, as opposed to 0.002-0.060 ohms for ER sensors of similar geometry. MICROCOR™ yields MICROCOR™ yields improvements in both resolution and response time of about 100-2500 times that obtained using ER techniques. This resolution and response time is not decreased b y temperature noise, since the thermal coefficients of magnetic permeability are several orders of magnitude lower than the equivalent parameters for electrical resistivity. Although temperature compensation is required, the same principle can be applied the same as with electrical resistance sensors and this is sufficient to almost eliminate spurious effects of temperature. 

Applications

The MICROCOR™ system MICROCOR™ system is used in oil and gas industry to monitor corrosion rate internally in many applications such as oil and gas transmission pipelines, water injection plants, Wasia water supply wells, GOSPs, refinery plants, etc. Extensive evaluation of the MICROCOR™ system was conducted in Saudi Aramco R&DC under an aggressive wet sour gas and Shaybah brine at higher higher pressures. The results of the study study indicate that it is feasible to use the MICROCOR™ for MICROCOR™ for on-line corrosion monitoring. In addition, the MICROCOR™ system MICROCOR™ system was subjected to field trials in Saudi Aramco facilities, such as Shaybah, Hawiyah, Barry, and Abqaiq Plant 462. Figures 1 and 2 show show MICROCOR™ transmitters MICROCOR™ transmitters were installed in Aramco fields. Off-line MICROCOR™ system MICROCOR™ system was installed in downstream of Barry Wasia water well to study the effectiveness of squeez e corrosion inhibition program as shown in Figure 1. 1. On-line single channel of MICROCOR™ system was installed in water downstream of WSOP to study the water corrosivity at Abqaiq GOSP-3 as s hown in Figure 2.

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Figure 1 – Off-line Microcor system was installed in Barry Wasia water well for corrosion monitoring before and after squeeze inhibition program



Figure 2 - On-line Microcor system was installed in water downstream of WOSP to study water corrosivity at Abqaiq GOSP-3

System Description

Several MICROCOR™ systems are available; on-line and off-line monitoring techniques. Common elements to all systems are a probe, transmitter, and data collection system. The MICROCOR™ systems can be configured as: o

Single channel data logger.

o

Single channel computer interface.

o

Multi-channel computer interface.

The off-line single channel system is shown in Figure 3. The system consists of the following: o

Probe/plug assembly

o

Probe adapter

o

Transmitter

o

Data logger

o

Set/record/retrieve software

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Figure 3 – Photos of the Off-Line MICROCOR™ System Components

The on-line single channel computer interface s ystem is shown in Figure 4. The system consists of the following: o

Probe

o

Probe adapter

o

Transmitter

o

Power supply

o

Converter

o

Record/retrieve software

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Figure 4 – Schematic Representation of the Single Channel MICROCOR™ System

The multi-channel computer interface is similar to the single-channel system described previously. The only difference is that this system is designed to monitor corrosion at many locations using a channel for every location. 

MICROCOR ™ Advantages

The advantages of the MICROCOR ™ are; o

MICROCOR ™ has high resolution and is sensitive for on-line monitoring.

o

MICROCOR ™ is not affected by temperature variation.

o

MICROCOR ™ works in all environments.

o

MICROCOR ™ is not affected by FeS films. Page 7 of 40

Document Responsibility: Materials and Corrosion Control Standards Committee SABP-A-036 Issue Date: 4 December 2011 Next Planned Update: TBD Corrosion Monitoring Best Practice o

o

Cost effective compare to traditional corrosion monitoring technique (Weight Loss).

o

Has a fast response time.

o

It does not require any user input.

o

It is easy to use.

o

On-line and off-line Corrosion Monitoring System.

o

o

o



Rapidly detects small corrosion upsets in systems with little or no corrosion allowance.

Corrosion can be monitored in many locations using Multi channels system. Amulet Software. (It runs as corrosion database, online & offline data, data plotting, transmitters diagnostics, reports, and easy configuration). Optimizing Corrosion Inhibitor Injections.

MICROCOR ™ Disadvantages

The disadvantages of the MICROCOR ™ are; o



Short life cycle of MICROCOR ™ probe, so the probe is consumed so rapidly in corrosive environments.

o

MICROCOR ™ system is intrusive monitoring technique.

o

MICROCOR ™ probe requires maintenance frequently.

Safety

It is very safe to install and handle the system. There are precautions need to be considered during MICROCOR™ probe installation. MICROCOR™ probe connectors must be kept clean for proper operation. To ensure this on Model 4000 series probe, an Overshot Adaptor should be fitted to the hollow plug during probe installation and retrieval. This seals the area of the probe connector from the process fluid during installation and retrieval. 

Contact Information

For more technical information about the system such as ordering parts, installation and operation, please contact supervisor at Corrosion Technology Unit/Material Engineering & Corrosion Control Division in Consultant Service Department.

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5.2

ClampOn System 

Background

Ultrasonic Testing (UT) uses high frequency sound energy to conduct examinations and make measurements. A typical UT system consists of several functional units, such as the pulser/receiver, transducer, and d isplay devices. A pulser/receiver is an electronic device that can produce high voltage electrical pulse driven by the pulser, the transducer which generates high frequency ultrasonic energy. The sound energy is introduced and propagates through the materials in the form of waves. The multi sensor technology (MST) consists of master unit with its sensors configuration. The system is based on Acoustic Guided Lamb Waves (AGLW) which is also known as plate waves. Propagation of Lamb waves depends on density, elastic, and material properties of the monitored system. They are influenced by frequency and material thickness. The two most common modes of particle vibration of lamb waves are symmetrical and asymmetrical as shown in Figure 5. One of the most important properties of AGLW is the dependence of the velocity and the frequency on the thickness of the structure through which they propagate. AGLWs also follow the contours of the structure in which they propagate, which enables them to travel relatively long distances with little attenuation. These two characteristics make AGLW an excellent candidate for continuously monitoring loss of wall thickness in p ipes. Knowing the dispersion curves of various materials enables MST to calculate the wall thickness and observe the growth of pitting along the signal path.

Figure 5 – Modes of Particle Vibration of Lamp Waves 

Applications

CEM or MST systems have been installed for field trials in two operating facilities: Shedgum Gas Plant and Yanbu Refinery. The CEM unit at Page 9 of 40


Shedgum was installed on a reducer with an outer diameter ranging from 16 inches to 24 inches at gas treat area # 3, making the standard mounting procedure not applicable at this location. The CEM system was installed on 8” pipeline downstream of the heat exchanger V14-E-0103B going to debutanizer in Area II at Yanbu Refinery, Figure 7. This location was selected because it has had a proven corrosion rate lately. Also, it can be installed on Pipelines, Pipe components, Storage tanks, Plate sections, etc. 

System Description

The principle of operation of MST is illustrated in Figure 6. A pair of slaves or sensors is used to excite and detect the Lamb wave in the material being monitored. The wave velocity is determined from a time-of-flight measurement. Any change in plate thickness either as general wall thinning or localized pitting can be detected by the change in the Lamb wave velocity due to the dispersive nature of the modes. The proposed system consists of a master unit and up to eight “slave” sensors that generates, records, and analyzes ultrasonic signals to measure loss of wall thickness non-intrusively. The velocity of the ultrasound signals is affected by changes in wall thickness caused by such factors as corrosion, erosion and pitting. The instrument detects these changes and determines corrosion rate as a function of time. The manufacturer claims that the system can be used up to 180°C on pipe ranging in diameter from 2 inches to 56 inches and can detect changes of 1% of wall thickness. The instrument can be used to monitor sections of pipe between 0.15 to 1 meter long including elbows and tees. The system or sensor configuration and lay out is based on the sensors arrangements. All sensors transmit and receive ultrasonic signals which are controlled and processed by the master sensor. This creates a pattern of information for the measured section. The result of the measurement is a reading of the average wall thickness over this measured area.

Figure 6 – Schematic of MST Operating Principle Page 10 of 40


Figure 7 – Downstream of the Heat Exchanger V14-E-0103B Going to Debutanizer in Area II at Yanbu refinery 

Advantages and Disadvantages

Identifying a non-intrusive and an on-line system for monitoring will lead to increase the operational efficiency as well as safety through eliminating installation and retrieving process. Among the advantages of the new system, it has a very wide application ranges. It can be permanently installed for online monitoring at up to 180°C. The manufacturer of the system claimed sensitivity is 1% of the monitored wall thickness. This technology will enhance plant safety and reliability by identifying and monitoring losses in pipe wall thickness. 

Safety

Involvements of non-intrusive corrosion monitoring systems such as MST beside the current intrusive one such as coupons, ER probes, LPR probes and MICROCOR probes will lead to increase the operational efficiency, safety, and flexibility in accessing and monitoring difficult locations. The proposed system has a wide application with a broad range of benefits and breakthrough savings. Installation of MST (CEM) systems will provide an early warning before catastrophic failure can t ake place resulting in a timely remedial action to be taken. 

Contact Information

CSD/ME&CCD/CTU, ID and R&DC 5.3

High Temperature UT Monitoring Sensors (HTUT) 

Background

“High Temperature UT Monitoring Sensors” (HTUT) are designed to accurately monitor metal losses in pipes which are o perated at a high Page 11 of 40


temperature regime (up to 350°C). The sensors use ultrasound waves to measure the wall thickness very accurately at one selected location. The metal loss due to corrosion is an important issue for maintenance practices where the condition of the pipe has to be established in order to determine life expectancy and plan repairs and shutdowns. Such monitoring of metal loss would obviously diminish the risk of breakdowns that can lead to leakage or even sudden release of high pressure hydrocarbons affecting equipment reliability, safety and plant performance. (HTUT) are permanently installed on pipes where ac curate remaining wall thickness or corrosion rate information is required. They can only monitor a small area, and they are not a search or screening tool to find defect locations. These sensors are installed mainly at locations where corrosion has already been detected or a likelihood of corrosion exists. They are ideal for On-Stream Inspection (OSI) program for inaccessible locations. 

Applications

(HTUT) use flexible chain type clamps that can be installed on 2-inch to 30-inch pipes. For larger diameter pipes, customized clamps can be ordered. Currently, the maximum temperature that the sensors can tolerate is 350°C. 

System Description

This technology, provided by General Electric (GE), consists of a device based on conventional ultrasound where a normal transducer is attached to a 304 Stainless steel wedge delay line. The transducer and the delay line are mounted by means of an adaptable clamping system and a metal foil serves as couplant between the delay line and the surface of the pipe. High Temperature UT sensors are devices meant to be a fixed monitoring location to survey remaining thickness in pipes operating at temperatures up to 350°C (662°F). It works with conventional ultrasound (UT) by means of compressional or longitudinal waves generated by 5 Mhz piezoelectric transducers which allows it to achieve a good resolution and sensitivity in thicknesses from 3 mm up to 16 mm in mild steel. The adaptable clamping system holding the transducer and its delay line can be observed in Figure 8 along with the probe used.

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Adaptable Clamping System

Figure 8 – Mounting of the High Temperature UT Sensor and Core Element HT-350x Sensor

The system can be connected to a device named CMX-HT sensor node which determines the actual thickness by observing and analyzing the change in the signal coming from the 304 Stainless steel delay line. This arrangement was shown in Figure 9 for both safe and hazardous areas.

Figure 9 – High Temperature UT Sensor Performance Enhanced by Adding Data Processing Devices 

Advantages o

o

Applicability: these sensors could be used by all the operating facilities at Saudi Aramco High temperature operation Page 13 of 40


o



Assist in corrosion monitoring and On-Stream Inspection (OSI) program for inaccessible locations; these sensors eliminate the need for scaffolding or shutdown during OSI program, as well as inspection scheduling

Disadvantages o

o

o



Convenience: these sensors allow for constant monitoring of pipe w all thickness

Sensors can only monitor a small area Not a search or screening tool to find defect locations; mainly installed on locations where corrosion has already been detected or there exists a high likelihood of corrosion Limited applicability as these sensors are mainly suited for monitoring general corrosion

Safety

It is very safe to install and handle. Typical sensor installation & retrieval safety precautions & considerations should be emplo yed, in addition to additional safety concerns arising from the potential for operation in hightemperature environments. 

Contact Information

For more technical information about the system such as ordering parts, installation and operation, please contact specialists at Inspection Technology Unit of Inspection Department. 5.4

GUL Permanently Installed Monitoring Sensors (GPIMS) 

Background

GUL Permanently Installed Monitoring Sensors (GPIMS) are generally designed for inspection and monitoring of road crossings and buried pipes. This technology involves a permanent installation of monitoring sensor that generates guided waves using Wavemaker G3 System. The generated guided wave travels along the pipe wall and reflections from defects and welds are detected by the sensor. The GPIMS can be easily installed on critical locations that are more vulnerable to corrosion and usually hard to reach. Guided Wave Testing (GWT) is one of the methods for piping and road crossing inspection. The mechanical waves which are guided by the walls of the pipe, can travel over long distances and provide rapid and near

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100% inspection coverage within the test range. Over the last decade the conventional role for GWT was to screen pipes for defects above a specific severity (normally >5% of the pipe cross sectional area). However, repeated guided wave measurements enable a direct comparison with the previously taken baseline data. Using GWT monitoring technique (GPIMS) allow identifying smaller changes (corrosion) that were undetectable by the conventional GWT. 

Applications

The GPIMS System uses low frequency guided ultrasonic waves that propagate along the pipe wall and is designed for rapid screening & monitoring of long lengths of pipe to detect external or internal corrosion as well as circumferential cracking. Generally, GWT can detect and provide the locations of corrosions, but it cannot produce accurate remaining wall thickness measurement. Therefore, GPIMS are mostly used as a long range screening tools for pipe inspection. Furthermore, the range of inspection depends heavily on the condition of the pipe. Table 1 shows the working envelop of guided wave testing for road crossings inspection. Table 1 - Guided Wave Testing Working Envelop for Inspection of Road Crossings Road Crossing Type

Inspection Range (m)

Sensitivity Level

Confidence Level

Sleeved (FBE)

50+

High

High

Buried, FBE

5-10

Mid

Low

Buried (Tape wrapped)

2-5

Low

Low

Field trials of GPIMS system were conducted in two major Saudi Aramco operating facilities (South Ghawar Producing and Hawi yah Gas Plant) to inspect ten road crossings with different configurations. The conditions of these road crossings are being monitored by the facilities. 

System Description

The GPIMS System is composed of three primary components: 1)

The GPIM Sensor : GPIMS sensor is produced as a low profile flexible transducer array which is clamped and bonded in place on the pipe surface. The whole transducer is then sealed in a polyurethane jacket to provide complete environmental protection from water and hydrocarbon

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damage. The unit height is about 3/8″ (away from the cable exit position) giving a wide range of possible install location.

Figure 10 – Respectively from left to right: GPIM Sensor, Polyurethane Jacket, Weather Proof Box

GPIMS can be installed on almost any pipe, with transducers currently installed on most sizes between 2” and 42” diameter. Currently GPIMS are restricted to pipes operating at no more than 120ºC. The GPIMS connector is in a sealed weatherproof box. This stores the test parameters such as pipe size, orientation and the identification of the reference. 2)

The Wavemaker G3 Instrument : GPIMS instrument provides electronic connectivity to the sensors and data storage of the results. It is a compact, lightweight and battery operated instrument designed for field usage. It has enhanced processing techniques such as dynamic frequency and bandwidth sweeping of the post processed data and focusing capability. This instrument can be used at temperature range of -30°C to +50°C.

Figure 11 – the G3 Instrument

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3)

The Data Acquisition and Analysis Control Unit : This is a controlling computer which analyzes the Guided Wave data and provides the final report. Guided Waves are generally very complex and every aspect of the wave excitation, reception and analysis need to be carefully controlled in order to optimize range and sensitivity.

Figure 12 – Data Acquisition and Analysis Control Unit 

Advantages o

o

o

o

o

o

o



GPIMS system can be used for monitoring and inspecting large distances of overhead piping and FBE coated sleeved road crossing piping. The range of inspection of bare piping can be more than 100 m with a good sensitivity and high confidence level. The range of inspection of FBE coated sleeved road crossing piping can be more than 50 m with a good sensitivity and high confidence level. Sensitivity to detect pipe cross sectional changes of 1% or less (this also depends on pipe conditions and configuration). Circumferential location and angular extent of defects (C-Scan and focusing) Long connection cables to allow for the selection of the best GPIMS location. Permanently installed on inaccessible pipe without needin g to access the pipe again.

Disadvantages o

GPIMS system is not an effective tool for inspecting large distances of buried piping at the road crossing. If monitoring is desired, several sensors may have to be used within 5-10 m intervals.

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o

o



The range of inspection of FBE coated buried road crossing piping can be 5-10 m with moderate sensitivity and low confidence level. The range of inspection of tape wrapped buried road crossing piping can be 2-5 m with low sensitivity and low confidence level. The system cannot measure the remaining wall thickness accu rately and it is mostly used for screening purposes.

Safety

These sensors are very safe to install and handle. Precaution should be taken, as required by the safety manual, when installing the GPIMS in high places or near a road crossing. 

Contact Information

For more technical information about the system such as requesting the service from a vendor, ordering, installation and operation, please contact specialists at Inspection Technology Unit of Inspection Department. 5.5

High Precision Corrosion Monitoring (HPCM) Sensors 

Background

The High Precision Corrosion Monitoring (HPCM) sensors are designed to monitor the metal losses in pipes and vessels very accurately. The sensor uses ultrasound to measure the wall thickness at one location. The metal lost due to corrosion is an important issue for maintenance practices where the condition of the pipe or vessel has to be established in order to determine life expectancy, program repairs and shutdowns. Such monitoring of metal loss would obviously reduce the risk of breakdowns that can lead to leakage or even sudden release of high pressure hydrocarbons affecting equipment reliability, safety and plant performance. HPCM sensors are permanently installed on pipes or vessels where accurat e remaining wall thickness or corrosion rate information is required. These sensors are meant to be permanently installed in inaccessible locations and the lead wire to be extended to a suitable location for data collection. The lead wire can be extended 50 meter from the sensor. HPCM sensors can only monitor the remaining wall thickness directly under the sensor, and it is not a search tool to find defect locations. These sensors are installed mainly at locations that corrosion has been detected or a likelihood of corrosion exists. Although these sensors are suited for monitoring general corrosion and erosion, nevertheless they can be installed on previously detected single

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corrosion pits that require monitoring. For example, HPCMS is ideal for On-Stream Inspection (OSI) program for inaccessible locations. 

Applications

HPCM sensors have very strong magnets that can be installed on any carbon steel vessels and pipes greater than 2-inch diameter. HPCM sensors can measure the wall thickness as low as 2 mm. Many of these sensors have been installed at several facilities throughout Saudi Aramco. All the installed sensors have been operating normally and by second quarter of 2011, some of these sensors have been in service for more than 2 years and providing thickness data to operators. The field trials of HPCMS were performed at two facilities. The first trial was at Abqaiq GOSP 3 on an elevated 20-inch pipe with 10 mm wall thickness. The sensor was installed on a pitting which had about 5 mm remaining thickness. This pipe had an operating temperature of 80°C. The HPCM performed perfectly on this trial and the remaining wall thickness from the corrosion pit is being constantly monitored by inspector at Abqaiq GOSP 3. A second trial was performed in two buried trunk lines located in Shaybah Producing Department (SPD). Two sensors were installed on two trunk lines and baseline readings were successfully taken from both sensors. The technician who is responsible for corrosion monitoring was ad equately trained to continuously monitor the remaining wall thickness of the corrosion pits. SPD can now monitor the corrosion rate while adjusting the amount of corrosion inhibitor added to crude oil. This will result in cost saving for their operation. 

System Description

HPCM sensor is a device meant to be a fixed monitoring location to survey remaining thickness in pipelines, piping and vessels. It works with conventional ultrasound (UT) by means of compressional or longitudinal waves generated by 5 and 10 MHz piezoelectric transducers which allow it to achieve a good resolution and sensitivity in thickness up to 30 mm. The transducer is held by a plastic housing which is put and maintained on the inspection surface by means of two strong permanent magnets. This can be observed in Figure 1 below. This transducer uses the same design as the normal incidence single element transducer, but include s a column of material that separates the transducer front surface from the surface of the pipe. The lead wire from the HPCM sensor can be extended 50 meter to a convenient location for inspectors to take the reading. The thickness reading can be taken by any ultrasonic thickness gauging device.

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Document Responsibility: Materials and Corrosion Control Standards Committee SABP-A-036 Issue Date: 4 December 2011 Next Planned Update: TBD Corrosion Monitoring Best Practice 

Advantages o

o

Permanent installation to monitor corrosion Can be used to monitor corrosion of inaccessible locations and eliminate use of scaffolding or excavation

o

Provide very accurate thickness reading

o

Provide corrosion rate

o

Can measure thickness as low as 2 mm

o

Can be used on surfaces with temperature of 80°C

Figure 13 – Design of the Transducer Fixture

The fixture is designed to hold single element transducers, or single element transducers with an attached delay line. The transducer is also spring-loaded against the pipe surface to maintain uniform contact over time. The design still requires the use of an epoxy film between the transducer face and the pipe surface. 

Disadvantages o

Provide thickness reading for only one location (thickness under the UT transducer)

o

Cannot be used in surfaces with temperature more than 100°C

o

Can’t be installed on vessels and pipes less than 2-inch diameter.

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Document Responsibility: Materials and Corrosion Control Standards Committee SABP-A-036 Issue Date: 4 December 2011 Next Planned Update: TBD Corrosion Monitoring Best Practice 

Safety

These sensors are very safe to install and handle. Typical sensor installation & retrieval safety precautions & considerations should be employed. These sensors require the same considerations as for any UT thickness gauging measurement. 

Contact information

For more technical information about the system such as ordering parts, installation and operation, please contact specialists at Inspection Technology Unit of Inspection Department. 5.6

Corrosion Coupons 

Background

Corrosion coupon testing consists of the exposure of a small specimen of metal (the coupon) to an environment of interest for a period of time to determine the reaction of the metal to the environment. Corrosion coupons are used to evaluate corrosiveness of various s ystems, to monitor the effectiveness of corrosion mitigation programs, and to evaluate the suitability of different metals for specific systems and environments. The coupons may be installed in the system itself or in a special test loop o r apparatus. Corrosion rates shown by coupons and most other corrosionmonitoring devices seldom duplicate the actual rate of corrosion on the system piping and vessels. Accurate system corrosion rates can be determined by nondestructive measurement methods or failure frequency curves. Data furnished by corrosion coupons and other types of monitors must be related to system requirements. High corrosion rates on coupons may be used to verify the need for corrective action. If a corrosion-mitigation program is initiated and subsequent coupon data indicate that corrosion has been reduced, the information can be used to approximate the effectiveness of the mitigation program. This section does not contain information on monitoring for intergranular corrosion, stress corrosion cracking (SCC), or sulfide stress cracking (SSC). Coupon size, metal composition, surface condition, and coupon holders may vary according to the test system design or the user’s requirements. Coupons are often installed in pairs for simultaneous removal and average mass-loss determination. Coupons may be used alone but they should be used in conjunction with other monitoring methods such as test nipples, hydrogen probes, galvanic probes, polarization instruments, resistance-type Page 21 of 40


corrosion monitors, chemical analysis of process streams and nondestructive metal thickness measurements, caliper surveys, and corrosion failure records. 

Application

Corrosion coupons measure the total metal loss during the exposure period. They show corrosion that has already occurred. A single coupon cannot be used to determine whether the rate of metal loss was uniform or varying during the exposure period. Information on the change in corrosion rate can be obtained by installing several coupons at one time or utilizing other monitoring techniques such as on-line corrosion probes. In addition to mass loss, important factors to consider in the analysis and interpretation of coupon data include location, time onstream, measured pit depth, surface profile (blistering, erosion), corrosion product and/or scale composition, and operating factors (e.g., downtime, system flow velocities, upsets, or inhibition). Additional information can be obtained within a system by varying one exposure parameter at a time (e.g., location or duration of exposure). For example, corrosion rates can be affected by changes in fluid velocity within a system. Corrosion rates can vary dramatically upstream and downstream from the point of entry of a corrodent, such as oxygen. o

System Description 

Types of Corrosion Coupons

Corrosion coupons are available in many different sizes and configurations. The size and configuration selected depend on the type of holder being used, line size, and entry orientation. Corrosion coupons can take a number of shapes, Figure 14, Basic shapes of corrosion coupons are as follows: a)

Strip

b)

Rod

c)

Disc

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Figure 14 – Basic Types of Corrosion Coupons

Different types access fittings devices that allow installation and retrieval under pressure may require a specific type of coupon. In addition, Coupon holders are available in many sizes and shapes to hold one or more flat or round type coupons. Coupon holders to secure a disk-type coupon flush with the pipe wall are available. Coupons flush with the pipe wall are subject to less turbulence than coupons that protrude into the flowing stream. Therefore, the flushmounted coupons should provide information that is more representative of corrosion on the pipe wall. Some common coupon holders are shown in Figure 15.

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Figure 15 – Common Coupon Holders with Different Access Fittings

When a coupon is installed, the following must be accomplished. Depending on the system, corrosion coupons may be mounted in a variety of ways. Mounting must accomplish the following:



a)

Adequate support of the coupons in the system.

b)

Electrical isolation of the coupon from other coupons, from the coupon holder, and from the pipe or vessel wall, to prevent galvanic corrosion.

c)

Provision for easy and rapid changing of coupons in the field.

d)

Coupon holders should be marked so the coupon orientation can be determined when it is in service.

Location in the System

To obtain the most reliable information from corrosion coupons, the coupons should be located where corrosion is occurring or is most Page 24 of 40


likely to occur. Corrosion and design engineers should collaborate to ensure that sufficient access fittings for corrosion monitoring are included in the design of new facilities. In existing operating plants, inspection records can identify corrosive areas. Replacement coupons should have the same orientation as previous coupons. Records should indicate the exact location of the coupon in a line or vessel (i.e., top, middle, or bottom). The following locations for coupons should be considered: a)

Stagnant fluid areas

b)

High-velocity fluid streams and impingement points

c)

Downstream from points of possible oxygen entry

d)

Locations where water is likely to collect, Figure 16

e)

Amine streams that contain sour gas

f)

Areas where a liquid/vapor interface occurs

Figure 16 – Areas of Possible Water Accumulation in Hydrocarbon Lines (NACE RP0775-2005) Page 25 of 40




Exposure Time

Exposure time must be considered when interpreting corrosion coupon data. Short-term exposure (15 to 45 days) provides quick answers but may give different corrosion rates than long-term exposures. Aggravating conditions, such as bacterial fouling, may take time to develop on the coupon. Short exposure times may be advantageous when evaluating inhibitor effectiveness. When coupons are used to evaluate and monitor corrosion-inhibitor treatment, new coupons should be installed just prior to treatment. This is particularly important when there is a long period between treatments (as in inhibitor squeeze, tubing displacement, and infrequent batch treatment of gas wells). Longer exposures (60 to 90 days) are often required to detect and define pitting attack. Multiple coupon holders can be used so that both the short- and long-term effects can be evaluated. Because exposure time affects test results, exposure periods should be as consistent as practical. A tolerance of ±7% allows a variation of ±2 days on a 30-day exposure. This is satisfactory for most applications. 

Handling and Corrosion Rate Calculation o

Field Handling Before and After Exposure

Prior to coupon installation, record the following information: coupon serial number, installation date, name of system, location of the coupon in the system (including fluid or vapor phase), and orientation of the coupon and holder. A typical corrosion coupon report is shown inAppendix-A. Prior to coupon installation and after the coupons have been cleaned, handle them by suitable means to prevent contamination of the surface with oils, body salts, and other foreign materials. Clean, lint-free cotton gloves or cloths, disposable plastic gloves, coated tongs, or coated tweezers should normally be used. When the coupon is removed, record the coupon serial number, removal date, observations of any erosion or mechanical damage, and appearance of scale or corrosion product. Any other pertinent data such as shut-in time and changes in velocity and inhibitor treatment should also be recorded. The coupon should be photographed immediately after removal, particularly if appearance of the corrosion product or scale is important.

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Protect the coupon from contamination by oxidation and handling. Place the coupon in a moisture-proof or special envelope containing volatile corrosion inhibitor and send immediately for analysis. Do not coat the coupon with grease or otherwise alter it. Gentle blotting with tissue paper or a clean soft cloth may be desirable to remove moisture prior to shipment. Corrosion products or scale deposits should not be removed in the field. o

Laboratory Procedures for Cleaning and Weighting Coupons after Exposure

The following steps are a guideline for cleanin g the corrosion coupons prior to weighting. Adequate safety precautions (e.g., ventilation and PPE) should be followed in every step. Observations should be recorded at every step of the cleaning process:

o

a)

Record the coupon serial number and weigh the coupon to within ±0.1 mg.

b)

Visually examine the coupon and record observations. Qualitative analysis of adherent scale or foreign material may be p erformed.

c)

Immerse the coupon in a suitable hydrocarbon solvent to remove the oily materials. Rinse with isopropyl alcohol or acetone and dry in a gentle dry air stream.

d)

Immerse steel coupons in 15% inhibited hydrochloric acid to remove mineral scale and corrosion products. Numerous commercial inhibitors are available to protect the steel during acid cleaning.

e)

After cleaning, immerse the coupon in a saturated solution of sodium bicarbonate for one minute to neutralize the acid. Rinse with distilled water to remove the neutralizer.

f)

Rinse the coupon immediately in isopropyl alcohol or acetone and dry in a stream of dry air.

g)

A pre-weighed blank that was not exposed to the corrodent is recommended to be subjected to the cleaning process to ensure that mass loss from cleaning is not significant.

Corrosion Rate Calculation

A calculation of average corrosion rate, expressed as uniform rate of thickness loss per unit time in mils per year (mpy), is shown in below.

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Where: CR = average corrosion rate, mils per year (mpy) W = mass loss, grams (g) 2

A = initial exposed surface area of coupon, square inches (in. ) T = exposure time, days (d) 3

D = density of coupon metal, grams per cubic centimeter (g/cm ), Table 1. To calculate the Maximum Pitting Rate (PR). Determine the depth of the deepest pit and divide by the exposure time. The following Equation may be used to determine the maximum pitting rate:

In case a change in the corrosion rate unit is desires, the following conversion factors can be used: 1 mm/y = 39.4 mpy 1 μm/y = 0.0394 mpy (μm = micrometer) 1 mpy = 0.0254 mm/y 1 mpy = 0.001 in./y (inches per year) 1 mil = 0.001 in.

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Table2 – Density of Selected Metals





Advantages

a)

The technique is applicable to all environments - gases, liquids, solids/particulate flow.

b)

Visual inspection can be undertaken.

c)

Corrosion deposits can be observed and analyzed.

d)

Weight loss can be readily determined and corrosion rate easily calculated.

e)

Localized corrosion can be identified and measured.

Disadvantages

Data from corrosion coupons seldom correlate exactly with the rate of corrosion observed in the system. They offer an estimate of the corrosivity of the fluid, rather than a true measurement of the metal lost from the pipe itself. Page 29 of 40


In addition, corrosion coupons only provide cumulative retrospective information only. If a corrosion upset occurs during the period of exposure, the coupon alone will not be able to identify the time or duration of upset occurrence. 

Safety

One main factor to highlight is safety during coup on retrieval. Equipment, especially in sour hydrocarbon lines should be adequately purged and cleaned before retrieving the coupon. In addition, during laboratory cleaning, proper safety precautions should be made when handling chemicals. The use of ventilated hoods and proper PPE is mandatory when dealing with solvents and acids. 5.7

Chemical Analysis 

INTRODUCTION

Chemical analysis is an essential part of a corrosion monitoring program. Many chemical tests are available to detect corrosion. Other tests trace or measure the processes associated with corrosion. Chemical analysis measures the concentrations of the ions involved in the corrosion reactions. Repeated analysis at the same point helps to identify the types of changes taking place in the system as a function of time. Analysis at different points in the system measures the interaction between the fluid composition and the surface of the system. 

SAMPLING

The critical part of any chemical analysis testing is obtaining a meaningful sample. The sample must be protected from contamination or natural alteration from the time it is collected in the plant or in the field until the analysis is actually made. Freshness and minimal contact with atmospheric ox ygen is most critical for iron count and pH. The sample must be representative of the material of interest or the analysis will lead to false conclusions. The importance of good sampling cannot be overemphasized. For routine water samples, clean plastic bottles with tightly fitting plastic caps are recommended. The bottles – not the caps – should be carefully labeled to identify the sample. The caps could be switched accidentally. Never use a metal container or a metal cap. The water will corrode them and

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become contaminated with corrosion products. o

Access to the System

Usually hot tapping and welding of access points not in the original design weakens the system and may lead to failure at the welds. Thus, it is preferable for all sampling points to be included in the design stage. Guidelines for the location of sampling/monitoring points in oil field production systems include: 





Water Source Wells 

Upstream and downstream of filters



In flowline downstream of well head, located far enough from the well to avoid turbulence

Gas Lift Wells 

Install from side of line if water level permits.



If this is not possible, install from bottom of line.



Avoid dry exposure at top or sand erosion at the bottom of the line.

Water Injection Stations

Access points should be located between pieces of equipment and vessels – such as boots, surge tanks, pumps, and headers – to aid in locating problems such as oxygen entry. Access points should also be installed at the main inlets and outlets to the station. 

Water Injection Wells

Access points should be located in straight sections – but not the meter run – of the system and preferably between two valves to allow shutdown if needed. 



Oil Wells 

In flowline near well head with the sampling done from the bottom of the line



Not too close to the well head or a valve so as to avoid turbulence

Oil Flow Stations 

Bottom of incoming pipelines or headers Page 31 of 40






Drain line of three-phase separators upstream of water drain/dump valves



Tank bottoms/surge tank bottoms



Drain lines of desalters/heater treaters upstream of water drain/dump valves



Gas outlets from two-phase separators to flare/compressors



Gas main to compressors (vertically down from near bottom or from bottom)

Tank Bottom  



Close to bottom of tank, typically 0.5 meters from floor Not in downcomer inside tank or any other static environment where oil might collect

TYPES OF CHEMICAL ANALYSIS

Several chemical analysis methods are available for assessing corrosive environments and monitoring changes. o

o

o

o

o

o

o

o

Water analysis – To determine the variations in ion concentration of water pH – To monitor and adjust the degree of acidity for use in corrosion control in glycol systems, drilling fluids, and plant applications Deposit analysis – To determine the composition of corrosion products in order to identify types of corrosion problems or to detect changes in the system Residual chemical – In certain cases, to determine the amount of corrosion inhibitor present, chlorine dosages for microorganism control, or sulfite dosages for oxygen scavenging Gas analysis – In most cases, to determine concentration of acid gases such as CO2 and H2S Oxygen analysis – To determine the content of dissolved oxygen in water and oxygen in gases Iron count – In most cases, to monitor inhibition programs in sweet gas or oil wells Bacterial activity – To determine the activity of various types of bacteria, especially sulfate reducers

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Water Analysis

Periodic analyses of water samples can indicate ch anges in corrosivity of systems. They are often the initial step in solving corrosion, scale, or pollution problems. The importance of water analysis is very evident. Water treatment is based on the results of the analysis. Casing leaks in producing wells can be detected using the results of water analyses. Compatibilities of waters for injection in secondary recovery can also be predicted from water analysis data. The chemical and physical properties of water are greatly influenced by the types and concentration of dissolved substances in it. Routine water analyses in the petroleum industry include measurement of pH, specific gravity, specific resistivity, and determinations of the concentration of carbonate, bicarbonate, sulfate, chloride, iron, calcium, magnesium, sodium, and total dissolved solids. Generally, the corrosivity of water containing dissolved salts increases with increasing salt concentration until a maximum rate is reached, and then the corrosivity decreases. If a water analysis indicates a corrosive water, then measures for preventing corrosion can b e included in the initial design. It is more effective and less costly to know a water is corrosive and design for the corrosivity than to modify the system after it has been constructed. On-site analysis of certain ions is desirable. Reactions can occur in samples to change the equilibrium of some ions. Bicarbonate (HCO3-) can convert to carbonate (CO3-2) when dissolved CO2 comes out of solution. Iron can oxidize to Fe2O3 unless the sample is preserved with acid. Therefore, on-site analysis is sometimes needed. On-site analysis of various ions in water can be a ccomplished by using colorimetric kits or digital titration. Colorimetric kits produce a color showing the presence and concentration of the specific ion. In titration, the amount of reagent needed to reach a certain visual standard is related to the concentration of the specific ion. pH

pH is a measure of a solution’s acidity. A pH of 7.0 is neutral and is neither acid nor base. A pH greater than 7.0 means that the solution is alkaline. The highest pH possible is 14.0. A pH less than 7.0 means that the solution is acidic. The lowest pH possible is 0.0. pH is an important factor when considering scaling tendencies of water. pH values greater than 7.0 support scaling tendencies while pH values below 7.0 do not support scaling tendencies but will render the water more corrosive with materials such as Page 33 of 40


steel. Some materials might corrode more readily in alkaline rather than acidic conditions, and the engineer must know the limitations of materials during pH swings. The pH value is best determined in situ or immediately upon taking the sample. The pH values of aged samples are usually worthless. Laboratory pH values for field water samples are usually not equal to the pH in the system. Since pH is a function of ions and dissolved gases, it can change with time. Oxidation of iron followed by precipitation of ferric hydroxide can act to raise the pH. Loss of dissolved gases like CO2 and H2S will also increase the pH. Therefore, pH should be measured on-site to be meaningful. Deposit Analysis

The chemical analysis of samples of corrosion prod uct and deposits in a system can be an important part of a monitoring program. Samples may be taken directly from piping or vessels or from coupo ns exposed to the system. For instance, samples can be obtained when a scraper is run through a pipeline. Knowledge of the composition of such deposits helps to determine the type of problem and to detect changes in the system. Proper sample collection and handling are extremely important. Full details on the dates, conditions, and locations of the samples are very helpful in interpreting this data. NACE Recommended Practice RP0173, “Collection and Identification of Corrosion Products”, gives excellent guidelines. Samples of corrosion products can change chemically after they have been removed from a system. For example, when iron sulfide comes in contact with air, it oxidizes to iron oxide. A sample that was black from iron sulfide when collected may turn brown from ferric iron oxide by the time it reaches the laboratory. Thus, the color of the sample when it was collected is very important information. Laboratory analysis for chemical composition should always be performed on these samples. Residual Chemical

The measurement of residual oil field chemicals can b e very helpful in troubleshooting a treating program. Chemicals such as sulfite for oxygen scavenging or chlorine for bacterial control in fresh waters have their residuals checked to optimize treating programs. Both field colorimetric kits and online monitors are available to check these residuals. Page 34 of 40


Sulfite concentrations in boilers and process waters must be routinely monitored to avoid overtreatment. While sulfite removes oxygen, an excess of sulfite can lower the pH and make the water corrosive to steel. Other useful information is the inhibitor concentration in a fluid. It helps determine when to retreat. Laboratory procedures include atomic absorption or fourier infrared spectroscopy used to determine inhibitor concentrations. One very simple field test to determine the presence of inhibitor in a system is the copper ion displacement (CID) test. In this test, a coupon is dipped in or exposed to the inhibited fluids and then immersed in a saturated copper sulfate solution. Where an inhibitor is present on the coupon, no copper will deposit. Copper will deposit on those areas not filmed by the inhibitor. Therefore, this examination can lead to a qualitative measure of the inhibitor presence. Gas Analysis

Gas analysis is an excellent tool when evaluating the corrosivity of a system. Both carbon dioxide and hydrogen sulfide in the presence of water can be corrosive. In gas wells or gas handling, determination of the carbon dioxide and hydrogen sulfide is fairly routine when the y are present in large quantities. Trace quantities of hydrogen sulfide are harder to detect but can be of extreme importance. For instance, traces of hydrogen sulfide can cause cracking of high-strength steels. If the H2S partial pressure is 0.05 psia or greater, then sulfide stress corrosion cracking resistant materials are needed. The corrosivity of carbon dioxide is a function of pressure and is based on the partial pressure of CO2. In many flowing gas wells, corrosion occurs where water condenses and carbon dioxide combines with it to form carbonic acid. Produced gas analysis can be routinely performed in the laboratory with chromatography. Periodic analyses can determine the changes in CO2 content. Analysis for H2S must be conducted on-site, however. H2S often reacts with steel sample containers and may not be detectable if a long delay exists between sampling and analysis. Oxygen Analysis

Oxygen dissolved in water is probably the most troublesome corrosive agent. Oxygen concentrations as low as 0.05 ppm can cause serious problems in water injection systems. Oxygen can enter systems through loose packing, ineffective pump seals, open tanks, or inadequate inert gas blankets.

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Oxygen in the presence of water can greatly increase the corrosivity of other gases such as carbon dioxide and hydrogen sulfide. Industry experience indicates that a solution containing carbon dioxide and oxygen is 10 to 40% more corrosive than the sum of the corrosion caused by each of the individual gases. There are several methods used to measure dissolved oxygen in water: colorimetric kits and membrane probe oxygen meters. Colorimetric kits quickly measure dissolved oxygen in water to the parts-per-billion (ppb) level. The membrane probe oxygen meter is designed to measure oxygen content in both liquid and gaseous mixtures. It is capable of measuring oxygen levels below 10 ppb. Iron Count

One of the easiest, quickest, and least expensive techniques for predicting corrosion and evaluating inhibition is determination of the iron content of the system fluid, also known as iron count. From samples taken at regular intervals, plots of iron counts versus time are constructed. Any significant increase in iron is interpreted as an increase in corrosion within the system. This technique is particularly useful in monitoring the effectiveness of inhibition programs where the reduction in iron content from pretreatment levels indicates the success of the control. Iron counts are the most widely used method for monitoring downhole corrosion rates in gas and gas condensate wells that produce little or no H2S. In these wells, carbon dioxide is the primary corrosive agent. In addition, organic acids are frequently present. They tend to keep iron in solution for at least a few minutes prior to oxidation after a water sample is taken from the wellhead or flowline. Iron analyses in sour systems are not as representative as those in sweet systems. Chunks of iron sulfide peel off periodically, causing a distortion in the iron count. Some sand formations containing clays, such as chlorites, produce water with a natural iron content. This background iron concentration is usually constant in relation to the volume of formation water in the total produced water at the wellhead. Therefore, treatment with a corrosion inhibitor would not normally reduce the iron content in the produced fluids below the level of formation iron.

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Bacterial Activity

In testing for bacterial contamination, sampling locations is extremely important. Since these organisms tend to grow in stagnant areas, it is very important to test areas such as tank bottoms and low areas in lines. Bacteria can live in groups or colonies attached to solid surfaces or suspended in water. Bacteria attached to a surface are called sessile bacteria while bacteria suspended in water are called planktonic bacteria. It has been reported that in a typical system, there are 1,000 to 10,000 times as many bacteria attached to a surface as there are floating in the water. It should be noted that the presence of bacteria does not necessarily mean trouble. However, if the bacterial counts show an increase with time or across a system, there might be bacterial corrosion occurring.

4 December 2011

Revision Summary New Saudi Aramco Best Practice.

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Appendix-A – DA-950035-001

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Appendix-B – Corrosion Coupon Report Data Type

Value and Unit

Facility and Unit 3

Flow Rates (Oil)

m /day

Flow Rates (Water)

m /day

Flow Rates (Gas)

m /day

Temperature

°C (°F)

Pressure

3 3

MPa (psig)

Fluid Analysis Gas Analysis Coupon Location in the System (sketch the system with coupon position) Coupon Number Material Surface Finish Exposed Area Dimensions Installation Date

M-D-Y

Installation Mass

grams

Removal Date

M-D-Y

Removal Mass

grams

Days in System

Days

Mass After Cleaning

grams

Mass Loss

grams

Average Corrosion Rate

mpy

Deepest Measured Pit

mil

Maximum Pitting Rate

mpy

Description of Deposited Before Cleaning Analysis of Deposit Description of Coupon after Cleaning (e.g. corrosion, pitting, erosion) Chemical Treatment During Exposure Other Comments

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SABP-A-036

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