Corrosion management requires an integrated approach that combines inspection, monitoring, process control, chemical treatment, and system data to optimize the
corrosion control program. The corrosion management program is part of the SARCOP team approach to optimization of the crude unit. Corrosion management includes the regular measurement and reporting of KPIs (Key Performance Indicators).
10.1 Responsibilities
The Saudi Aramco refinery fully qualified on-site corrosion engineer will take the proactive leadership role in corrosion measurement and control in
cooperation with the SARCOP vendor and team members.
The SARCOP on-site vendor team member will report data and
recommendations at the morning meeting, weekly meetings, and other refinery functions as required by the refinery management.
10.2 KPIs, Example Corrosion Rates, and Reporting Schedule
Typical crude unit corrosion KPIs are presented in Table 2. KPIs agreed with a vendor could also include cost, delivery, and safety aspects. The selection of KPIs for a particular unit must be determined based on the specific unit history.
KPIs are dynamic, in that they may be adjusted periodically following the SARCOP procedures to set more appropriate KPIs for a particular unit, based on its history and other site specific factors. Basic KPIs will be measured each shift. Weekly reports shall be issued by the SARCOP vendor. Monthly and quarterly summary reports will be issued. Each refinery must develop
procedures for measuring, recording, and reacting in an appropriate and timely manner to KPI deviations.
Table 2: Typical Crude Unit KPIs
Performance Indicator Method Target Accumulator iron content Hach spectrophotometer method, or equivalent < 1 ppm
Corrosion rates Corrosion coupons, electrical resistance probes,
or high sensitivity ER probes (Microcor) < 5.0 mpy pH On-site pH probe & narrow range paper in
addition to refinery laboratory determination 5.5 to 6.5 Accumulator chloride
content 10 to 30
ppm
Corrosion rates experienced in Saudi Aramco crude units vary significantly.
Overhead systems that are completely out of control have experienced corrosion rates on the order of 100 to 200 mpy. This order of corrosion rates is likely to lead to emergency repairs, welding patches, and total replacement of the overhead at the next opportunity. Overhead systems with moderate control experience corrosion rates on the order of 20 to 30 mpy. These types of rates are still too high but have been managed by corrective repairs during planned T&Is. A well controlled overhead system has target corrosion rate of 5 mpy or less.
One joint venture refinery has experienced serious tower corrosion problems including periods operating at 1.6 inches per year corrosion rate of carbon steel.
For rates of this magnitude, immediate and drastic control improvements must be made.
One Saudi Aramco refinery has experienced corrosion rates of 20 mpy on its Monel strip lining. These are very serious corrosion rates due to the thickness of the lining. Major replacement of the lining should be planned for the next T&I.
Hastelloy-clad carbon steel pipework will have a corrosion rate of 1 mpy or less.
10.3 Data Storage and Processing
Data are stored in various systems. Plant process data and data from the Laboratory Management System are stored in the PI (Plant Interface) system.
Data are archived indefinitely so that data can be retrieved and retroactively analyzed. Inspection data from OSI (on-stream inspection) programs are stored in the SAIF program (System Assurance and Inspection of Facilities) program.
This program is in the process of being implemented in refineries. Previously data were stored in programs such as PIPE+, Ultra PIPE+, and IDEEAL.
Corrosion probe data are stored in corrosion servers of various descriptions.
Normally, Corrosion servers in Saudi Aramco are the responsibility of the corrosion engineer and do not provide direct input to the distributed control system. Amulet is frequently specified with new corrosion monitoring systems from Rohrback Cosasco Systems such as the Microcor corrosion monitoring system. Amulet is a corrosion management software that allows input of many types of corrosion measurement and other data. The SARCOP chemical alliance program has, as part of its contract with Baker Petrolite, the agreement to install Amulet Plus in the refineries and to provide access to the data by Consulting Services Department. Amulet Plus is Baker Petrolite’s customized version of Amulet which includes functions related to chemical tracking and usage, plus the ability for automated report publishing.
The new purchasing procedures of SARCOP where the vendor is reimbursed as the chemical is injected will result in the development of a large data base of accurate treatment rates for each unit. Previously, this was not possible.
10.4 On Stream Inspection (OSI) Program and Inspection Methods
On Stream Inspection data are ultrasonic wall thickness measurements that allow damage that has occurred to the system to be measured. The technique has medium sensitivity, so that measurements are usually made after a number of months or years, though for very severe corrosion, damage can be monitored in a matter of weeks. The typical detection level with skilled operators is 1 to 2 percent wall loss. Ultrasonic thickness measurements can be made while the
plant is operating or not. Conventional probes may be used up to temperatures of about 56ºC (130ºF). High temperature probes are available for on-stream inspection up to 385ºC (725ºF). The limitation of OSI capability is often the inaccessibility of the monitoring location which may require extensive scaffolding to reach the needed location. API 570 specifies inspection of
hydrocarbon processes every five years or less. Where a corrosion rate has been determined and a remaining life can be calculated before the minimum
allowable thickness is reached, SAEP-20 specifies re-inspection after no longer than 25% of the remaining corrosion life has been consumed. SAEP-1135 describes the steps necessary to plan and operate a program for on-stream inspection.
Claddings are difficult to monitor in service. Strip lined claddings will reflect ultrasonic thickness measurement signals from the steel/alloy interface. Weld overlaid claddings will have poor signal reflection quality due to the weld bead surface. Explosive bonded cladding or co-extruded cladding have been
successfully measured by UT in some situations.
Rightrax (GE Inspection Technologies) is a permanently installed UT
measurement strip. It has potential application in inaccessible locations. It has proved reliable up to 130ºC (265ºF) but will fail above that temperature. Even short duration high temperature spikes may inactivate the tool. Other
technologies such as Clamp-on are still being evaluated but offer potential solutions for future application.
RCS is developing ULTRACORR, a high sensitivity, permanently installed UT measurement system.
Any spot measurement including OSI test point locations may miss localized corrosion. The OSI test point locations should cover all impingement locations (tees and elbows).
Some Plant Inspection Units performed close monitoring on the crude overhead piping by conducting P-SCAN surveys on selected locations.
Some Plant Inspection Units performed infrared surveys on crude overhead lines to check for cold spots. These can be used to indicate possible condensation areas due to inhibitor injection.
Fired heaters can be inspected during T&Is using FTIS Intelligent Pig by Quest Integrated. This has been used at Ras Tanura Refinery. The FTIS Intelligent Pig uses ultrasonic inspection and dimensional sizing to provide data on corrosion and creep. The tool is propelled through the complex bends of the fired heater using water. It is suitable for heaters with tubing from 4 to 8 inches in diameter. The total linear distance that can be measured is 5300 feet with a
minimum bend radius of 1D. Typical inspection speed is 2 feet per second meaning that a heater with 2000 linear feet can be examined in 15 minutes.
Results are available in several convenient formats. www.qi2.com 10.5 Injection Point Inspection
Plant Inspection Units must perform injection point inspection programs as per Inspection Procedure 01-SAIP-04, and API RP 570 on all chemical injection points, including the wash water injection point. The inspection of injection points must include removal of injection quills for visual inspection and UT readings during scheduled T&I shutdowns. This should be done routinely at every refinery even if there are T&I time limitations.
Inspection programs on caustic injection quills installed immediately upstream of the heater must be performed as directed. Inspection during installation requires on-site verification of quill metallurgy and post-installation radiography of the quill to ensure correct positioning. Caustic quill locations must be
inspected every 3 months for the first year after any work such as replacement or any modification to the quill is completed. Thereafter, they must be inspected yearly. Radiography to confirm the condition and position of the quill is required each time.
10.6 Corrosion Monitoring Systems
Formal recommendations must be obtained through the Responsible
Standardization Authority for Corrosion Monitoring, who can be contacted via the Supervisor, Corrosion Technology Unit, Materials Engineering and
Corrosion Control Division, Consulting Services Department.
Corrosion monitoring systems installed in Saudi Aramco refineries include coupons, conventional electrical resistance probes, and high resolution, high speed electrical resistance probes such as Microcor by Rohrback Cosasco Systems (RCS). State of the art systems use Microcor probes interfaced to the host computer through the plant’s existing LAN computer network. Some applications have used fiber optics for data transfer. Basic components of the Microcor station include the probe, the explosion proof data transmitter with RS 485 field bus. 32 transmitters can be connected to a single cable. See product information on the RCS website:
http://www.rohrbackcosasco.com/datasheets/products/Microcor%20Online.pdf The addition of a modern corrosion monitoring system in a new project provides the opportunity to reroute data output from old existing systems which may have obsolescent electronics into spare slots in the new data processing system.
Probes or coupons are mounted in the system through permanently installed, intermediate pressure, packing gland system such as those provided by RCS.
The intermediate pressure system can be operated with an intermediate pressure retractor which has significant advantages over the weight of high pressure retriever systems. See product data on the RCS website:
http://www.rohrbackcosasco.com/datasheets/products/Model_60.pdf High pressure retrievers are not recommended for on-line use in refining applications because of the high weight of the retriever, the high weight of the service valve, the large platform sizes need to operate them safely. In addition, high pressure retrievers require extensive training to operate safely and regular maintenance.
Coupons should be changed every three months or so. Microcor probes should generally be selected to give a year or more service before replacement.
10.7 Laboratory Testing
Laboratory work is extremely important to the safe and profitable operation of the refinery. Chemical treatment programs to control corrosion can only be successful and cost effective if laboratory data is of high quality and timely in its delivery. It should be emphasized that, as far as laboratory personnel are
concerned, there is no good or bad result. Instead, the target is obtaining accurate results.
A challenge in many refinery operating systems is the lag time between sample collection and data availability. Timeliness of feedback of data from refinery laboratory analyzed data is essential and each refinery must minimize the time between sample collection and data availability. It is best practice to use on-site instant read-out techniques such as a field-located pH meter or close-range pH paper covering the range 7.5 to 4.5 pH. Field collected data must be recorded and stored along with laboratory derived data. Any differences should be investigated.
Some refineries are now using automatic e-mail announcements of off-specification values. This is proving to be an excellent way to get data to corrosion engineers and others so that corrective action can be considered.
Calibration of pH meters on-site at or near the crude unit must be performed at least once a day using buffer solutions. Dry pH electrodes must be avoided at all the times.
For sediments in crude, ASTM D 4007 is often used. It is extremely important to completely comply with ASTM D 4007. For example, the temperature must be controlled during centrifuging at 60 ± 3ºC. The more accurate ASTM D 473,
Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method, should be used on a monthly basis to check results from ASTM D 4007.
For water in crude, ASTM D 4007 is often used. However, ASTM D 4006, Standard Test Method for Water in Crude Oil by Distillation or ASTM D 4928, Standard Test Methods for Water in Crude Oils by Coulometric Karl Fischer Titration, are more accurate and should be used on a monthly basis to validate the results of ASTM D 4007.
For salt in crude, ASTM D 3230 is often used. However, ASTM D 6470, Standard Test Method for Salt in Crude Oils (Potentiometric Method) is more accurate and should be used on a monthly basis to verify ASTM D 3230 data.
At low ppm levels, the accuracy of the potentiometric method is ±0.5 ppm. At 25 ppm the accuracy is ±1.5 ppm. Where equipment is available, ion
chromatography (IC) is the best method. IC typically yields slightly lower measurements than those obtained with potentiometric methods.
Iron in crude can also be measured following ASTM D 5863 A, Standard Test Methods for Determination of Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry.
Revision Summary 24 June 2007 New Saudi Aramco Best Practice.