PARÁGRAFO VI CALIDAD VISUAL
PRODUCCIÓN LIMPIA, CONSUMO SUSTENTABLE Y BUENAS PRÁCTICAS
High-acid crude (HAC) oils, also called high-total acid number (TAN) crudes, are oils where TAN [expressed in terms of milligrams of potassium hydroxide per gram (mg KOH/g)] is more than 0.5. Acidity is mainly due to the presence of naph- thenic acids. These crudes trade at discounts of about $3/bbl to $10/bbl to conventional crudes; therefore, processing these crudes improves refinery bottom lines. However, processing high-TAN crudes is also challenging for refineries, especially those not designed to handle naphthenic crudes.
Refinery asset reliability during high-TAN crude process- ing is paramount. Hardware changes—i.e., upgrading mate- rials construction from carbon steel (CS) and alloy steel to stainless steel (SS) 316/317, which contains molybdenum and is significantly resistant to naphthenic acid corrosion— are complicated tasks for refineries. They call for a large capi- tal investment as well as a long turnaround for execution. Al- ternatives to hardware changes are corrosion mitigation with additives and corrosion monitoring with the application of inspection technologies and analytical tests.
Corrosion problems during HAC processing are caused by naphthenic acids. Corrosion is predominant at temperatures higher than 180°C, where shear stress on pipe walls is signifi- cant. Corrosion problems during the processing of HACs in the high-temperature section are normally mitigated by dosing phosphate ester- or sulfur (S)-based inhibitors at certain criti- cal locations inside the process units. The inhibitors are dosed in process streams with the help of injection quills.
In addition to inhibitor dosing, intensive corrosion moni- toring and analytical tests play a major role in equipment and piping health monitoring and in analyzing stream properties online. Corrosion-monitoring equipment includes custom- ized inspection technologies with both intrusive and non-in- trusive systems.
Naphthenic acid corrosion mitigation. Naphthenic acid corrosion is determined by TAN, naphthenic acid number (NAN), temperature, S, velocity (shear stress) and flow re- gime. During naphthenic crude processing, corrosion at high temperature is mitigated by injecting either phosphate-based ester additives or S-based additives. These additives provide an adherent layer that does not corrode or erode due to the effect of naphthenic acids.
In HAC processing, higher S content in feed means lower risk for corrosion. Sulfur has an inhibitive effect. The corrosion
rate has been observed to jump with the same rate of inhibitor dosing in a changed crude mix (i.e., when low-S crudes with the same TAN value are processed).
The high-temperature corrosion inhibitor is dosed into the process streams, normally at a concentration of 3 ppmw–15 ppmw. The additive is mixed with the suitable process stream, typically at a ratio of 1:30. It is injected into the cooled stream (< 100°C) with specially designed corrosion-mitigation quills, since the inhibitor is highly corrosive to CS, alloy steel and even SSs. The dosage limit of phosphorous (P)-based inhibi- tors is decided based on the allowable P levels in the vacuum gasoils (VGOs) going to hydrocrackers (HCs) and fluid cata- lytic crackers (FCCs).
Overhead corrosion management. In addition to naph- thenic acid corrosion at high-temperature sections of units, overhead corrosion in crude and vacuum units is a major con- cern. In high-TAN crude processing, acidity increases signifi- cantly in the overhead of atmospheric and vacuum units, as these crudes generally contain higher concentrations of salt, sediments and sometimes organic chlorides.
Desalting these crudes is difficult and, therefore, salt carry- over to the overhead is more likely during high-TAN crude pro- cessing. Naphthenic acid molecules at high temperatures also decompose to form organic acids that become concentrated in the overhead systems of atmospheric and vacuum units. There- fore, desalter management and corrosion control and monitor- ing are critical in the crude distillation unit (CDU), the vacu- um distillation unit (VDU), and sometimes in the visbreaking and bitumen units. Desalter residence time, washwater injec- tion rate, mixing valve differential pressure, and efficacy of the emulsion breaker all play vital roles in corrosion management.
Corrosion monitoring is normally done using coupons, electric resistance probes or linear polarization resistance- based probes that are installed in the overhead line, down- stream of the air fin cooler or condensers. Chloride (Cl), pH and iron (Fe) content in the prefractionator and main fraction- ator overhead receiver are maintained within limits.
Normally, accumulator boot water pH is kept in the range of 6–6.5; Cl is limited to less than 20 ppm; and Fe is kept below 0.5 ppm. Salt content at the desalter outlet is also monitored and maintained. For corrosion mitigation, filmer and neutralizer amine are injected into the overhead. Intermittent washwater dosing in the overhead to remove salts and corrosive substances
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is also performed. Many refiners use online analyzers for con- tinuous monitoring of pH, Fe and Cl. Closed-loop automated controllers are also utilized to optimize dosing.
Corrosion monitoring by nondestructive testing. Online corrosion coupons have been widely used in critical process cir- cuits for the assessment of fluid corrosivity. Normally, alloy-steel and CS coupons are used for corrosion monitoring.
Coupons can be fixed or retractable. In retractable coupons at high-temperature locations, a proper sealing system should be used. Coupons can also be of different shapes and types. The shape can be rectangular, circular or helical, and may be nor- mal or pre-stressed. Based on the corrosion rate of coupons (for both general and pitting corrosion), the corrosive nature of the fluid can be assessed, and dosing of additives can be optimized.
Electric-resistance probes. Online electric-resistance (ER) probes are the most widely used, intrusive corrosion-monitor- ing devices that give the corrosivity of the fluid and measure corrosion rate in the stream. The ER probes, which are made of the same metallurgy as that of the main pipe, are inserted through stubs connected to the pipe. The probes detect the process fluid and undergo corrosion in the circuit.
The electric resistance of the probe changes with corrosion and deterioration, and the change in resistance corrosion rate is measured (FIG. 1). These probes do not measure the exact
corrosion on the pipe; instead, they measure the corrosivity of the fluid in that particular circuit (FIG. 2). During high-TAN
crude processing, circuits with process fluid temperatures above 180°C are most susceptible to corrosion and, therefore, ER probes are inserted into these lines.
Normally, these probes are installed at furnace inlet lines of atmospheric and vacuum units, atmospheric and VGO cir- cuits, reduced crude oils and short residue circuits. They are also used in the FCC feed line (preferably in the filter loop) and the HC feed line (at around 200°C, before the charge en- ters the reactors).
Locations are identified based on the flow conditions and line geometry. Ideal locations are pump individual discharges, control valve loops downstream of control valves, near ther- mowells, etc. Normally, isolatable loops are preferred. A com- putational fluid dynamics (CFD) study is performed to iden- tify ideal locations. If the study offers a non-isolatable loop, a retractable design is selected for the ER probe (FIG. 3).
Refiners are using various advanced versions of ER probe- based systems that have high levels of accuracy and sensitivity and that are proven for measuring corrosion in high-temper- ature lines during naphthenic crude processing. These high- sensitivity probes have an expected life of three to four years and will almost instantaneously respond to a 10-mils-per-year (mpy) change in corrosion rate. Traditional, flush-mounted ER probes need about a week to detect 10-mpy changes in corro- sion rate. The thinner the element, the faster the response; like- wise, the thicker the element, the longer the probe life.
Two forms of probe element are available—flush and cylin- drical—and there are several mounting configurations to choose from, the most common of which allows the probes to be insert- ed and removed under full process operating conditions without shutdown. Flush probes are used for best thermal performance where flush mounting with the pipe wall is desirable or essential. A typical example is a bottom-of-line location. In these applica- tions, water films commonly collect in the bottom of the line and are the primary cause of corrosion. The flush probe ensures that the whole of the probe element is exposed to the water film. Therefore, it is well suited for CDU and VDU overhead lines.
Cylindrical probes are suited to virtually any aggressive envi- ronment, since there is no sealing material other than the parent metal. The measurement area of the element is much greater in this design and is suitable for use in a single-phase flow.
Field signature methods. In addition to ER probes, nonin- trusive systems like field signature methods (FSMs) are used at certain critical locations, such as furnace outlets, transfer lines, etc., for monitoring the health of equipment and piping at high temperatures and velocities. These are normally used where two-phase flow exists at relatively higher temperatures and inaccessible locations.
FSM corrosion measurements are done directly on the pipe and fittings, whereas ER probes measure the corrosivity of the process fluid. FSMs consist of multiple sensors (metallic pins) that are spot-welded in a rectangular pattern on the pipe/bends at the most critical locations (FIG. 4). An electric current is passed
from one side of the matrix to the other, and the voltage between the pins and the critical area is measured. This gives a unique electric field signature that depends on the geometry and thick-
HK CR ER pr obe r eadings, c orr osion r at e in mils per y ear 0 5 10 15 20 25 30 VGO RCO Inhibitor: Nil 3 ppm 6 ppm 9 ppm 12 ppm 15 ppm
FIG. 1. ER probe readings in mpy with change in inhibitor dosing rate for different process streams during high-TAN crude processing.
Extension adapter
Hollow plug assy
Probe Pipeline
Corrosion probe system Access fitting body, flareweld, buttweld, flanged
Heavy protective cover (optional)
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ness of the pipe and the electrical conductivity of the metal. Any change in field (or signature) resulting from internal corrosion or erosion is revealed by a change in voltage across the sensor pins.
Online FSM logs are available with permanently installed data-loggers that collect readings on a real-time basis. They have a high level of accuracy, and sensitivity is typically on the order of 0.05%–0.1% of pipe wall thickness. The system can be set up to communicate with the refinery control system so that data can be reviewed remotely.
A unique advantage of FSM measurement is that it gives area coverage rather than point measurement. It detects thickness loss even in the locations between the pins. Advantages of FSM corrosion rate are that it can be accurately measured at high temperatures from remote sections of the plant, it provides an operator to the facility to optimize the corrosion control pro- gram, and it responds quickly to increased corrosion.
Other nonintrusive techniques. In addition to FSMs, several other non-intrusive, online monitoring techniques have become popular in recent years. However, most of these techniques are ultrasonic-based and, therefore, are point contact-type devices. This means that they do not cover the entire surface area on which the sensors are positioned. Some of these systems are spot- welded, while others are simply clamped and, therefore, can be moved to other positions. These instruments are generally used at locations other than furnace outlets and transfer lines, such as control valve loops and bends at pump discharge (usually on 6–8-in.-diameter lines) and distillation unit overhead systems.
These alternative nonintrusive systems are often used to validate ER probe readings over a longer duration. The unique advantage of such systems is wireless communication. Alterna- tively, some technologies use permanently installed ultrasonic probes on pipes and equipment to directly measure thickness. These instruments can be clamped onto the pipes, and online data can be gathered.
The main disadvantage of these systems is that they mea- sure point thickness and do not capture the area. Also, they are not as accurate or as sensitive as FSMs. However, these systems can be used in place of ER probes, and they are less expensive than FSMs.
Hydrogen-permeation method. Aside from ER probes and FSMs, there are portable instruments that measure hydrogen (H2) flux on the pipe. The basis of this technology is that cer-
tain modes of corrosion in a refinery result in the generation of atomic H2, and, when atomic H2 diffuses through the metal
wall and permeates outside the pipe wall, this forms a molecule. By monitoring the changes in H2 diffusion rate, the variation
of internal corrosion can be inferred. These portable measuring devices can be used whenever required and can operate at high temperatures.
Radiography. Conventional and digital radiography are other proven, nondestructive techniques for assessing piping and equipment health during HAC processing. Conventional film radiography can be used as a scanning tool, but it lacks quanti- tative capability. Radiography is not a 24/7 online monitoring system, although it has mobility that allows it to be deployed at a much wider area and at many locations.
In digital radiography, the main advantage is a quantitative approach that provides for online, condition-based assessment of risk. Some machines use solid-state X-ray technology in digital radiography, which is fast, portable and shows the per- centage of metal loss. It does not require scaffolds or insulation removal.
Analytical tests. In addition to these equipment reliability- monitoring systems, analytical tests of process streams are vital to HAC processing. The monitoring of TAN, NAN, metals and P is of high importance. TAN and NAN are routinely measured in different process streams to optimize dosing of inhibitors. Potentiometric titrators are normally used for TAN measure- ment, while NAN is measured using the Fourier transform infrared spectroscopy (FTIR) method. Elements—mainly metal—are monitored with Inductively coupled plasma (ICP) mass spectrometry or ICP optical emission spectrometry in- struments. These machines use inductively coupled plasma for elemental analysis.
Some metals in process streams are measured from a corro- sion viewpoint. Vanadium (V) and nickel (Ni) are measured to monitor the content of the heavy metals in VGO streams that go to the FCC or to the HC, as these are poisonous to FCC and HC catalysts. Sometimes they also impact product yields.
Additionally, P content in process streams must be moni- tored. This is because inhibitors for high-TAN crude are P-
FIG. 3. Retractable ER probe installed in process piping at a refinery.
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based compounds, and there are certain restrictions on the allowable limit of P in the catalyst of cracker units. A typical schedule of analytical tests is shown in TABLE 1. A comparison
of several corrosion-monitoring devices used in high-TAN crude processing is shown in TABLE 2.
Takeaway. Refineries that are not designed for HACs should install these instruments beforehand and collect base data dur- ing conventional high-S and low-S crude processing.
These instruments together give a holistic picture regarding the in-service corrosion and deterioration of equipment during HAC processing (FIG. 5). Corrosion-mitigation methodology is
finalized after a thorough technical audit of the refinery is un- dertaken. CFD is also performed during the audit to detect vul- nerable locations. Refiners can form a multidisciplinary group consisting of representatives from process, inspection, opera- tions, quality control and other disciplines for smooth execu- tion of these activities.
The objective is to minimize risk and reduce metal loss. However, with this approach, it is relatively safer to limit crude TAN to 1. Above that level, selective metallurgy upgrading (e.g., certain bends of high-temperature piping, packed beds, etc.) is required. With the best of the inhibitors, the corrosion rate in VGO circuits can be brought down to 7–8 mpy, which is still very high compared to the normal corrosion rate at a refinery. Therefore, a refinery should carry out a thorough risk- based inspection to further increase the crude TAN level.
SANJIB GHOSHAL joined Indian Oil Corp. in 1997 and is the inspection manager at the company’s Mathura refinery. He holds a degree in metallurgical and materials engineering from the Indian Institute of Technology in Kharagpur, India, and has 15 years of experience in inspection and corrosion management. Mr. Ghoshal specializes in corrosion issues during high-TAN crude processing in refineries. Other areas of interest include strategic planning for asset- reliability improvement and risk-based inspection. He has published papers on corrosion and fouling issues related to cooling water, and the application of advanced inspection technologies.
VIKAS SAINIK joined Indian Oil Corp. in 2008 and presently serves as the senior inspection engineer at Indian Oil’s Mathura refinery. His responsibilities include inspection and corrosion monitoring at refinery atmospheric and vacuum units. Mr. Sainik holds a degree in metallurgical and materials engineering from the Indian Institute of Technology in Roorkee, India, and possesses more than five years of experience in inspection and corrosion management. Specifically, he has worked in corrosion management for high-TAN crude oil processing.
TABLE 1. Typical schedule for an analytical test
Stream Analytical test Frequency Crude tank TAN, S, density,
Fe, Ni, V Every shift (three shifts per day) NAN Daily Pre-topping column bottom
TAN, S, Fe, Ni, V Every shift (three shifts per day) NAN Daily Heavy kerosine circulating refl ux (HK CR)
TAN, S, Fe, Ni, V Daily
P Daily
NAN Daily
Aviation turbine fuel/aviation turbine fuel circulating refl ux and naphtha
Similar to HK CR Daily
Light GO CR/heavy GO/ reduced crude oil/light VGO/light diesel oil/heavy VGO
Similar to HK CR Daily
Vacuum slop/vacuum residue TAN, S, Fe, Ni, V Every shift (three shifts per day)
NAN Daily
Vacuum bottoms unit/ bitumen feed
TAN, S, Fe, Ni, V Daily
FCC/hydrodesulfurizer/ HC unit feed
TAN, S, Fe, Ni, V, P Daily
TABLE 2. Comparison of corrosion-monitoring devices used in high-TAN crude processing
System Online Portable Non- intrusive Directly measures wall loss Where to use
ER probe Yes No No No Process fl uid in
single phase; temperature of
180°C–300°C
FSMs Yes No Yes Yes Furnace outlet
transfer lines H2
fl ux method
No Yes Yes No Any location
required High-
temperature ultrasonic measurements
No Yes Yes Yes As required
Online high- temperature
ultrasonic probes
Yes No Yes Yes Substitute
for ER probe or other fi xed corrosion- monitoring device