5 Reasons Why Performance Evaluations are Essential for Your Processing Units
Annual health checks for Sulfur Recovery Units (SRU) and Amine Units have become an industry standard, ensuring operational performance and reliability form ongoing operations and before scheduled turnarounds.
1-Establishing Baseline Performance
Baseline performance data is crucial for assessing the current state of SRUs and Amine Units. This data acts as a reference point, allowing operators to detect deviations from normal operations. Without a baseline, identifying specific issues becomes challenging, leading to extended downtime and increased maintenance costs.
2-Early Detection of Issues
Regular health checks enable early identification of operational inefficiencies, potential corrosion, contamination, fouling, and other issues. Catching these problems early helps prevent them from escalating into costly shutdowns or safety incidents.
3-Optimization Opportunities
By regularly analyzing system performance, SRE’s health checks reveal optimization opportunities. This could involve setting new operating parameters, fine-tuning the amine circulation rates, or adjusting the temperatures within the SRU. These improvements can lead to better recovery rates, lower emissions, and reduced energy consumption.
4-Supporting Turnaround Planning
Comprehensive health checks provide valuable data for planning turnarounds. Knowing the condition of equipment and potential trouble areas allows for precise scheduling and resource allocation, minimizing downtime and optimizing repair efforts.
5-Ensuring Compliance and Safety
In industries dealing with hazardous materials like H2S, safety is paramount. SRE’s rigorous safety protocols, including the use of SCBAs and trained engineers for sample collection, ensure that all health checks comply with the highest safety standards, protecting personnel and the environment.
Sulfur Recovery Engineering (SRE) offers comprehensive health check services that go beyond routine maintenance, establishing baseline performance, pinpointing optimization opportunities, and identifying potential issues early to avoid costly unscheduled and emergency shutdowns.
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Overcoming Heat Stable Salts: Enhance Your Amine Treating Process
Introduction
In the operation of amine units, the degradation of the solvent is a common issue caused by contaminants such as oxygen, sulfur dioxide, acids, or acid precursors present in the feed gas. One of the most significant problems arising from this degradation is the formation of Heat Stable Salts (HSS). Understanding the formation, impact, and remediation of HSS is crucial for maintaining the efficiency and longevity of amine treating systems.
Formation of Heat Stable Salts
Heat Stable Salts are formed when acid anions like formate, acetate, thiosulfate, thiocyanate, and chloride react with amine molecules. These salts are termed "heat stable" because they cannot be regenerated by heating. Various sources contribute to HSS formation:
In refineries, gases from the Fluid Catalytic Cracking Unit (FCCU) can contain formic and acetic acids.
Oxygen in refinery gas streams or air leaks in gas gathering systems can lead to the formation of carboxylic acids.
HCN in the feed gas can react with sulfur in the amine solution to form thiocyanate.
Impact of Heat Stable Salts on Amine Systems
The presence of HSS in amine systems leads to several operational issues:
Reduced Acid Gas Carrying Capacity: HSS bind with amine molecules, decreasing the amount of amine available for acid gas absorption.
Corrosion: High concentrations of HSS can be corrosive, facilitating corrosion reactions and dissolving protective films on metal surfaces.
Foaming: Changes in the surface-active properties and increased viscosity of the solution can lead to foaming, which disrupts operations.
Erosion: The precipitation of salts or corrosion end products can accelerate the erosion of metal components.
Addressing the Problem
Reducing or removing HSS from the amine solution is essential for maintaining system efficiency. The following strategies can be employed:
Monitoring and Prediction: Regular solvent analyses to determine the HSS profile and predict when remedial action is necessary.
Control Strategies: Adjusting operational configurations to reduce the formation of contaminants or improve the removal of contaminants upstream.
Neutralization Technology: Using neutralizers to convert HSS into less corrosive forms, thereby extending the solvent's life.
Solvent Purification: Employing methods such as electrodialysis, ion exchange, or vacuum distillation to remove HSS.
Our experts can help you find the root cause of the problem and provide tailored solutions to maintain your system's efficiency and reliability.
Advantages of Managing Heat Stable Salts
Effective management of HSS offers several benefits:
Reduced Corrosion and Equipment Replacement Costs: Minimizing the corrosive impact of HSS extends the life of equipment.
Optimized System Capacity: Ensuring maximum acid gas removal efficiency prevents unit shutdowns and maintains operational targets.
Lower Maintenance Costs: Reducing the frequency of system cleanings and filter replacements lowers maintenance expenses.
Environmental and Economic Benefits: Avoiding solvent disposal reduces environmental impact and costs associated with solvent replacement.
Conclusion
Managing Heat Stable Salts in amine treating systems is crucial for maintaining system performance and longevity. Regular monitoring, effective neutralization, and advanced purification methods can significantly reduce the negative impacts of HSS. At SRE, we offer comprehensive amine analysis services to identify the exact salts present and determine the root cause of HSS formation. Our detailed analysis capabilities ensure precise solutions to optimize your amine system's performance.
We can help
If you're facing issues with Heat Stable Salts in your amine treating system, contact SRE for a complete amine analysis. Our experts can help you find the root cause of the problem and provide tailored solutions to maintain your system's efficiency and reliability.
Mastering Amine unit Issues 8 Scenarios Where SRE Can Assist
Amine plants play a crucial role in gas sweetening, but they can face numerous operational challenges. Sulfur Recovery Engineering (SRE) offers specialized services to troubleshoot and resolve these issues, ensuring optimal performance and reliability. Here’s a brief description of each problem and how SRE addresses it:
1-Foaming
Problem: Heavy hydrocarbons and contaminants in the inlet feed cause foaming in absorbers, leading to reduced efficiency and potential operational disruptions.
Solution: SRE utilizes advanced Gas Chromatography (GC) technology for rapid identification of contaminants, along with onsite foam testing and evaluation of anti-foam agents to mitigate foaming issues effectively.
2-Corrosion
Problem: Corrosive environments within the amine plant can degrade equipment integrity, leading to increased maintenance costs and safety risks.
Solution: SRE quickly identifies corrosion potential areas through simulation, reviews and refines monitoring programs, and helps minimize corrosion through an online operations and maintenance (O&M) monitoring program.
3-Off-Spec Gas / LPG
Problem: Off-spec gas or LPG indicates deviations from desired product specifications, impacting product quality and compliance.
Solution: SRE conducts rapid onsite testing to diagnose issues, identifies trace sulfur components, and achieves 99% closure of the sulfur balance, ensuring compliance with product specifications.
4-Fouling
Problem: Fouling in amine plants results from contaminants and particulates accumulating in key components, reducing operational efficiency.
Solution: SRE reviews and optimizes filtration programs to prevent fouling, ensuring smooth operation and minimizing maintenance downtime.
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5-Sulfur Plant Feed Quality
Problem: Inaccurate sulfur component levels and impurities in the regenerator overhead impact the efficiency of sulfur recovery processes.
Solution: SRE performs onsite analytical testing to accurately measure sulfur components, identifies mercaptans breakdown, speciates BTEX compounds, and quantifies hydrogen cyanide (HCN) concentrations. We quickly optimize the acid gas circuit to improve overall efficiency and reduce corrosive issues.
6-Hydrocarbon Entrainment
Problem: Ineffective separation equipment allows hydrocarbons to enter the process stream, reducing the purity and efficiency of amine treatment.
Solution: SRE reviews and enhances the performance of inlet separation equipment, quantifying hydrocarbon levels in the process stream to mitigate entrainment issues.
7-Inefficient Energy Usage / High Carbon Intensity
Problem: Excessive energy consumption and high carbon intensity increase operational costs and environmental impact.
Solution: SRE optimizes energy usage through circulation rate adjustments and reboiler duty fine-tuning, recommends alternative amines with lower energy requirements, and assists in transitioning from steam to electric drives for enhanced efficiency.
8-Root Cause Analysis of Common Alarms
Problem: Common alarms such as pressure differentials, analyzer errors, and pH fluctuations indicate underlying operational issues affecting plant reliability.
Solution: SRE conducts detailed root cause analysis on absorber pressure differential (delta P), H2S and total sulfur analyzer errors, fuel gas H2S analyzer errors, sulfur plant tail gas analyzer (ADA) erratic behavior, quench pH, quench cooler fouling, and hydrogen analyzer plugging. Our expert analysis identifies operational inefficiencies and implements targeted solutions to improve overall plant reliability and safety.
SRE’s specialized expertise and innovative solutions address the complex challenges faced by amine plants, ensuring efficient operation, regulatory compliance, and enhanced performance. By partnering with SRE, clients benefit from reduced downtime, lower operational costs, and optimized plant reliability in their gas sweetening operations.
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Hydrocarbon Present in Amine Solvent Downstream of Absorber
Problem Definition A South American Refinery Client requested assistance tackling the problem of hydrocarbon being present in their amine solvent (rich amine). The client reported
Problem Definition
A South American Refinery Client requested assistance tackling the problem of hydrocarbon being present in their amine solvent (rich amine). The client reported an incidence of hydrocarbon in their acid gas stream going to SRU. They are looking into putting a flash tank in service for the amine circuit and require SRE’s analysis to determine prime location, operation guidelines, and instrumentation required. There was an existing flash tank and was put out of service long ago, the tank was designed as a charge drum for amine system. P&ID of the amine circuit was provided (flash tank situated after the lean-rich amine heat exchanger) along with their current option.
SRE’s Response
Within a couple of days of receiving the request, SRE reviewed the P&ID and information provided by the client to present the recommendations. Flash drum should be installed after the absorber, and before the lean-rich amine heat-exchanger, to ensure Hydrocarbon is condensed and a significant amount of H₂S is NOT flashed. As per industry practice, absorbers operating below 10 bar usually do not require a flash drum. It was advised to the client to further investigate the event of hydrocarbon carryover to ensure there is no permanent damage to the amine circuit/equipment.
A write-up was sent to the client explaining where the flash drum should be installed and what the limitations will be. In addition, operation guidelines and instrumentation requirements were also presented to the client. For the short term, the client was advised to ensure that the amine inlet separator is functioning well, and that extra precautions are taken to stop hydrocarbon from entering the amine circuit.
RESULTS
The client was fully onboarded with SRE’s recommendations. They will strive to ensure that the flash drum will be installed upstream of lean-rich amine heat-exchanger and that proper instrumentation will be used. Operation guidelines have been provided to the client and will be further refined as the need arises.
SRE continues to provide support to this client as they are in the process of the modifications.
Solids Contamination
Problem Definition European Refinery Client requested assistance with solids contamination in their DEA system. Corrosion issues in the regenerator bottom section and reboiler were reported.
Problem Definition
European Refinery Client requested assistance with solids contamination in their DEA system. Corrosion issues in the regenerator bottom section and reboiler were reported. Amine analysis results were sent to SRE for review.
SRE’s Response – Solids contamination
Within one hour of receiving the request, SRE provided review of DEA analysis results and reported to the client that Heat Stable Amine Salt (HSAS) levels were considerably higher than maximum guideline level of 2 weight percent and were the probable cause of corrosion in the regenerator and reboiler.
The contamination in the system was the result of high corrosion rates found in the unit. A report on HSAS management was sent to the client. Additional guidance was provided to the client on short-term mitigation of HSAS using neutralization to immediately reduce the corrosion problem.
RESULTS
Using SRE’s guidelines, the client was able to reduce HSAS to an acceptable level. Solids contamination and corrosion rates were reduced.
SRE continues to provide assistance to this client to maintain the unit within guidelines for HSAS, solids and corrosion.
Trace Oxygen in Raw Gas To Determine Corrosion Source
Q4 2017 saw SRE complete a number of interesting projects. For one gas plant in Canada, SRE was involved with determining the source of corrosion with our client’s gas sweetening unit.
Q4 2017 saw SRE complete a number of interesting projects. For one gas plant in Canada, SRE was involved with determining the source of corrosion with our client’s gas sweetening unit. In an amine system, corrosion problems can easily be identified by the color of the amine: pale green indicating light corrosion; brown indicating corrosion greater than the filtration capabilities; and black indicating dangerous levels. Although there are many sources for corrosion, our client had already identified that their corrosion was most likely cause by an increased amount of Bicine.
There are several mechanisms for producing bicine in amine gas treating facilities which include (1) reaction of diethanolamine (DEA) with glyoxal – a common hydrogen sulfide (H2S) scavenger – and (2) exposure of the heated gas treating solution to an oxidizer. Bicine impacts gas treating amine solutions in two ways. First, it forms heat stable amine salts (HSAS) and second, it increases the corrosivity of the amine solution. Here, it was thought that the oxidizer was Oxygen (O2) ingress from the field raw gas.
As such, SRE’s scope of work was to complete trace O2 analyses at various points through the gas plant, including the raw gas from each field and throughout the inlet lines to the Amine contactors. In one day, SRE conducted 22 trace O2 measurements from 10 different locations. Sampling was extensive as a 3-minutes sample time and portable equipment allowed the site Engineer to be able to request extra measurements for due diligence. These capabilities are in stark contrast to a trailer full of equipment and a 2-hour run time – 1 hour to mobilize, 30 minutes to warm up line and 30 minutes to conduct analysis – used by other testing companies, where 22 samples could take a few days & cost 3 times more.
Results ranged from 20 ppm to 250 ppm with all raw gas inlets having a measurable amount of O2. The site Engineer planned to use the data to conduct their own material balance and to continue to mitigate the amine system corrosion.