V. K. ARORA, Kinetics Process Improvements, Houston, Texas (U.S.)
Benfield carbon dioxide (CO2) absorption units are widely used in refineries, petrochemical complexes and ammonia plants for hydrogen (H2) purification, syngas cleanup and acid gas removal. Many now face declining performance due to aging designs, higher throughputs and mechanical wear.
This article outlines the systematic revamp of a high-throughput ammonia plant’s CO2 removal system—an approach equally applicable to refinery and petrochemical gas-treating services. The author’s company executed the study and process design, using validated simulation models, hydraulic assessments and mechanical evaluations to identify and address core constraints, including excessive steam usage, elevated CO2 slippage, limited flash drum capacity and declining ejector performance.
The revamp delivered restored hydraulic stability, reduced CO2 breakthrough, lower steam demand and improved energy efficiency, translating into higher ammonia yield and maximized incremental production. The methodology offers a transferable framework for upgrading Benfield units to achieve higher capacity, improved efficiency and long-term reliability.
Scope. The Benfield process remains a proven and robust technology for CO2 and acid gas removal in ammonia synthesis gas, refinery H2 units and petrochemical syngas trains. However, many operating systems are now pushed far beyond their original design capacities, with operational bottlenecks increasingly concentrated in the CO2 absorption section.
These constraints often manifest as reduced hydraulic capacity, solvent losses, high CO2 slippage and rising steam consumption. Left unresolved, they increase energy costs, impair downstream conversion efficiency and elevate the risk of unplanned outages.
This article focuses on one such system—designated Act-1—in an ammonia facility that had expanded to nearly 40% above its original design capacity. Previous modifications, including packing replacement, increased solution circulation and additional ejectors, could not prevent:
Persistent CO2 breakthrough, impacting ammonia and urea production
Escalating low-pressure (LP) steam demand
Progressive mechanical degradation affecting the reboiler, the flash drum and ejectors, leading to reduced performance and higher maintenance frequency.
The author’s company was engaged to perform a comprehensive performance assessment and develop a process design for a full-system revamp. The solution applied simulation-driven diagnostics, hydraulic and mechanical evaluations, and fit-for-purpose engineering to resolve root causes, providing a repeatable upgrade methodology for Benfield CO2 systems in high-demand industrial environments.
Background and system history. The ammonia facility was commissioned in 1992, with a nameplate capacity of 1,500 metric tons per day (tpd). Subsequent debottlenecking projects in 1997 and 2009 increased output to 2,125 metric tpd. However, the CO2 removal system was never proportionally upgraded. Core hydraulic and thermal designs remained unchanged, and only selective modifications were implemented. FIG. 1 shows the system configuration after the 2009 expansion.
Incremental modifications over the years. To accommodate steadily increasing plant throughput, a series of performance enhancements were introduced at different stages that:
Replaced random packing in the absorber with high-capacity packing to reduce flooding risk
Added supplementary ejectors in the 4th and 5th flash drum compartments
Installed chevron trays in the stripper overhead to minimize water and solvent carryover
Upgraded the stripper overhead condenser and reflux system
Modified the CO2 knockout vessel
Increased the Benfield solution circulation rate by ~17%
Increased potassium carbonate (~7%) and activator (~50%) concentrations
Added LP steam injection to both the stripper and ejectors.
While these measures provided temporary relief, they could not compensate for the underlying hydraulic, thermal and mechanical constraints of the original design. Under sustained high loading, system performance continued to decline, ultimately making a comprehensive, system-wide revamp unavoidable.
Pre-revamp operating challenges. By the time the author’s company was engaged, the CO2 removal system faced persistent constraints that eroded energy efficiency, mechanical reliability and production capacity:
High CO2 slippage: Breakthrough levels reached up to 4,200 ppmv vs. a design limit of 1,000 ppmv, increasing synthesis loop inerts, raising purge rates and lowering ammonia conversion. This, in turn, curtailed urea production potential.
Hydraulic instability: Frequent pressure drop excursions and near-flooding in the absorber and stripper indicated severe capacity limits and poor vapor-liquid distribution.
Elevated LP steam demand: This resulted in the overfiring of auxiliary boilers, excess steam venting in the urea unit, increased cooling and demineralized water use, and inefficient deaerator operation, all driving up utility costs.
Feed separator overload: Higher feed temperatures and flows led to solvent carryover and exchanger fouling downstream.
Undersized flash drum and ejector inefficiency: This constrained stripping performance and limited hydraulic flexibility.
Thermal inefficiencies: Fouled heat-transfer surfaces and restricted flow in the reboiler loop reduced thermal performance.
Progressive mechanical degradation: Deterioration of ejectors, flash drums and reboilers increased maintenance frequency and the risk of unplanned shutdowns.
Collectively, these issues compromised reliability, increased energy consumption and created sustained bottlenecks across downstream units during high-throughput operation.
Revamp approach. To address persistent hydraulic, thermal and reliability constraints, the author’s company developed and executed a two-phase revamp strategy in close collaboration with the plant’s engineering and operations teams. The plan combined validated process simulation, cost–benefit analysis and targeted process design, with execution by an engineering, procurement and construction (EPC) contractor following the author’s company’s process design package (PDP).
Phase 1: Simulation, diagnostics and assessment
Validated process simulation models: Calibrated to actual operating data under varying loads, enabling accurate bottleneck diagnosis and post-revamp performance forecasting.
System evaluation: Hydraulic, thermal and mechanical assessments of the absorber, stripper, flash drum, ejectors and reboiler circuits, including heat-duty analysis and equipment condition checks.
Cost–benefit screening: Upgrade scenarios evaluated for technical impact, feasibility and return on investment, factoring in layout constraints and vendor input.
Plant owner concurrence: Final scope agreed jointly with plant engineering and operations to align with priorities and budget.
Phase 2: PDP
Defined upgrades and optimized operating parameters, including:
Revised flash drum sizing and configuration
Specifications for new ejectors, and reboiler and column internals
Recommended setpoints for high-load operation
Formed the technical basis for procurement, budgeting and layout planning.
Following the author’s company’s PDP, the plant owner engaged an EPC firm for detailed engineering, procurement and installation. Commissioned in mid-2022, the upgraded CO2 removal system restored hydraulic stability, reduced CO2 slippage, improved energy efficiency and enabled reliable, sustained high-throughput operation.
Plant data vs. simulation. The author’s company developed a detailed simulation model of the Benfield CO2 removal system using a rigorous, rate-based framework. Actual plant operating data—including flowrates, temperatures, pressures, CO2 loading, solvent composition and utility usage—were integrated with original design documentation and field-verified equipment configurations. Special care was taken to accurately represent the installed column internals, including specific packing types and hydraulic capacities in both the absorber and stripper.
The model was calibrated to match observed behavior under high-throughput operation and validated against historical operating records. Key parameters—CO2 removal efficiency, pressure drop, steam usage and liquid distribution—showed strong agreement between simulation predictions and actual plant performance. This confirmed the model’s reliability as a decision-making tool for targeted upgrades.
TABLE 1 summarizes the comparison between simulated and observed performance metrics. Once validated, the model was used for targeted parametric studies to assess the impact of changes in:
Circulation rate
Packing configuration
Steam flow distribution
Ejector performance under elevated loads.
These studies quantified the technical benefits and feasibility of each potential modification, accounting for hydraulic limits and integration constraints.
FIG. 2 summarizes the predicted effects on CO2 slippage, column pressure drops and steam consumption. The insights from these simulations formed a data-driven foundation for final equipment selection and operating strategy during the revamp design phase.
Key findings. The Phase 1 study, conducted under base (normal) operating conditions, identified the following issues and improvement opportunities across the CO2 removal system:
Overall equipment loading. Nearly all major components operated at or above original design limits. Hydraulic constraints in the absorber and stripper columns significantly impaired vapor-liquid distribution, column efficiency and overall system performance.
Absorber column.
Flooding conditions: Beds 2 and 4 operated close to hydraulic limits [~98% capacity (FIG. 3)], risking incipient flooding.
Liquid distributors: The liquid distributors in the lower two beds were underrated and likely overflowing, reducing efficiency. Upper distributors, while near design capacity, had low drip density and poor liquid distribution. FIG. 4 shows the lower distributors at > 125% rated capacity, while upper distributors were nearing their maximum limits.
Vapor distribution: Excessive vapor velocity through the feed nozzle into Bed 4 caused maldistribution. Two installation options for a new vapor distributor were assessed: (1) hot-work installation during turnaround (TAR)—technically preferred but outage-dependent; (2) external installation with Bed 4 shortened/raised by ~1 m—less desirable due to loss of worker access.
Stripper column: Flooding and maldistribution.
Flooding conditions: Bed 4 operated at ~94% flood capacity (FIG. 5).
Liquid distributors: All four distributors operated above 140% of rated capacity (FIG. 6), leading to poor liquid distribution and degraded performance.
Vapor distribution: Two vapor distributors were recommended; hot-work installation feasibility to be confirmed during TAR.
Reboiler circuit: The liquid level in the reboiler could be increased by modifying the bottom chimney tray collector box (TAR hot work required).
Wash trays: Likely in spray regime due to low liquid rates, risking carryover. Action: Redirected cold condensate makeup from the reboiler vapor line to the wash trays to improve liquid loading.
Packing evaluation. The author’s company independently evaluated multiple packing configurations for both columns (TABLES 2 and 3) using the validated Benfield simulation model. Recommendation: Retain existing packings and defer replacement decision until post-revamp validation of upgraded vapor and liquid distributors. Key observations: (1) 4th-generation random packings offered better hydraulics but increased CO2 slippage, (2) structured packings showed potential for improved hydraulics and CO2 removal efficiency, but performance under high liquid load remains uncertain with limited full-scale validation.
Flash drum and ejector system.
Existing issues: The flash drum showed cracks in its internals/welds; several ejectors exhibited wear and declining efficiency. The drum was undersized, with inadequate vapor disengagement and residence time.
New design: The replacement drum was ~160% larger, retaining the original five-compartment layout to minimize piping changes. Each compartment has one, which was designed for existing LP steam conditions. Sensitivity analysis (FIG. 7) showed that higher steam pressure significantly reduced steam consumption, while steam superheat had minimal effect on steam use.
Stripper reboiler replacement
Rationale: Severe tube wall thinning posed reliability and mechanical integrity risks.
New design: The installation of a higher duty reboiler to increase CO2 stripping capacity and improve thermosiphon circulation, while fitting within existing space/piping limits. The longer tube bundle was accommodated without layout changes.
Benefits: Reduced steam demand, lowering auxiliary boiler load and greenhouse gas (GHG) emissions. Lower heat load on the demineralized water heater improved deaerator stability.
Recovery turbine. The turbine was already at full capacity with the largest impeller. The potential to recover ~225 kW of additional power would require significant modifications, including pump relocation. The cost-benefit analysis deemed an upgrade unjustified.
Separators. The absorber feed separator was significantly undersized, causing excessive vapor velocity and liquid carryover. The stripper’s overhead separator and treated syngas separator were adequately sized for current loads.
Key modifications and justifications. A comprehensive revamp was executed to address the hydraulic constraints, reliability risks and energy inefficiencies identified during the Phase 1 assessment. The major upgrades introduced in the 2022 revamp are outlined in TABLE 4 and reflected in the post-revamp process flow diagram shown in FIG. 8.
Absorber vapor distributor
Issue: Maldistribution and excessive inlet vapor velocity at the feed nozzle resulted in poor contact with the lower bed and localized flooding.
Solution: A vane-type vapor distributor was installed to ensure even vapor entry across the column cross-section.
Impact: Improved vapor distribution, enhanced mass transfer efficiency, reduced CO2 slippage and mitigated localized flooding risks.
Absorber liquid distributors
Issue: All four distributors were significantly overloaded, operating beyond their hydraulic rating, which caused uneven wetting and compromised bed performance.
Solution: Replaced with high-capacity, orifice-deck distributors designed to handle increased circulation rates and provide uniform liquid loading.
Impact: Improved column efficiency, stabilized hydraulic performance and restored reliable absorber operation.
Stripper liquid distributors
Issue: Severe maldistribution due to underrated liquid distributors constrained column separation performance.
Solution: All four distributors were upgraded to high-efficiency designs suited for current liquid flow requirements.
Impact: Ensured uniform wetting, improved CO2 stripping and reduced variability in product gas quality.
Flash drum replacement
Issue: The existing flash drum was undersized and mechanically degraded, limiting vapor disengagement and reducing ejector suction stability.
Solution: Installed a new vessel with 160% of the original volume, while retaining the five-compartment layout to simplify tie-ins.
Impact: Enhanced vapor-liquid separation, improved ejector reliability and reduced entrainment into downstream equipment.
Ejector system optimization
Issue: The original seven ejectors showed declining performance and elevated steam consumption due to age and wear.
Solution: Replaced with five modern high-efficiency ejectors optimized for the available LP steam conditions.
Impact: Lowered motive steam demand, eliminated reliance on higher LP steam headers and reduced venting in downstream urea operations.
Stripper reboiler upgrade
Issue: Tube thinning and reduced heat transfer in the existing reboiler posed a reliability risk and limited stripping efficiency.
Solution: A higher duty reboiler was installed, sized to fit within the original footprint and piping envelope.
Impact: Improved CO2 stripping capacity, reduced LP steam consumption and enhanced thermal stability, contributing to lower emissions and improved ammonia synthesis loop efficiency.
Feed separator (planned upgrade)
Issue: The absorber feed separator was undersized, leading to carryover of liquid droplets and impacting column hydraulics.
Solution: Replacement is scheduled for a future phase to match current feed conditions.
Justification: Enhancing disengagement capacity is critical to protecting absorber performance and minimizing solvent losses.
Power recovery turbine (deferred)
Issue: The existing turbine had reached its capacity limit, with no further impeller upgrades possible.
Solution: Upgrade was deferred due to the need for extensive piping and pump relocation.
Justification: Economic evaluation concluded that the estimated 225 kW power recovery did not justify the associated capital expenditure.
The simulation-driven revamp delivered lasting performance improvements, with the calibrated process model pinpointing critical upgrades and supporting a thorough cost-benefit assessment during design.
Key improvements realized.
CO2 slippage reduction: CO2 breakthrough decreased by approximately 1,500 ppmv (FIG. 9), improving synthesis loop composition and ammonia conversion efficiency. This directly enabled incremental production of ammonia and urea, with the plant achieving record, stable output post-revamp.
Restored hydraulic stability: Upgraded vapor and liquid distributors eliminated incipient flooding in both absorber and stripper columns. The absorber now operates stably with no differential pressure excursions, even at elevated throughput.
Utility efficiency gains: Reduced high-to-low-pressure steam consumption, curtailed auxiliary boiler firing and eliminated steam venting in the urea section, improving overall energy utilization and lowering operating costs.
Enhanced mechanical integrity: Replacement of the flash drum, ejectors and the reboiler addressed known deficiencies and improved long-term reliability. Maintenance intervals are extended, and the risk of mechanical failure has been significantly reduced.
TABLE 5 summarizes the key post-revamp operating metrics, confirming improved energy efficiency, stable throughput and enhanced reliability following the mid-2022 startup.
Takeaways. This project showed that legacy Benfield systems can be modernized to handle higher capacities, improve efficiency and extend service life, without costly layout changes. Using a simulation-led, economically optimized approach, every modification was fully rationalized to deliver maximum benefit at minimum cost, providing a proven, transferable model for gas-treating revamps in ammonia, refining and petrochemical operations. Key outcomes included:
Simulation-led design enabled precision upgrades: The author’s company validated Benfield's model, which accurately diagnosed bottlenecks, quantified improvement potential and supported a rigorous cost-benefit design process.
Hydraulic stability restored: Advanced vapor/liquid distributors, flash drum resizing and ejector replacement eliminated flooding and pressure drop excursions, ensuring uniform distribution under peak loads.
Performance and capacity gains achieved: CO2 slippage reduced by ~1,500 ppmv, enabling incremental ammonia and urea production, with reliable operation at peak output of 2,149 metric tpd.
Energy efficiency improved: Lower LP steam demand reduced auxiliary boiler firing, enhanced thermal integration and eliminated steam venting to the urea unit, cutting water use and GHG emissions.
Mechanical integrity secured: A new flash drum, ejectors and reboiler addressed degradation issues, extending service life and reducing maintenance frequency.
Transferable methodology: This approach provided a scalable revamp framework for legacy Benfield systems in ammonia, refining and petrochemical service, offering a proven path to higher capacity, efficiency and reliability. HP
REFERENCES
Arora, V. K., “Cost-effective revamp of CO2 removal systems in ammonia plants,” Nitrogen + Syngas Conference, London, UK, March 2017.
Arora, V. K., “Benfield system revamp experience at Yara plant,” Nitrogen + Syngas Conference, Barcelona, Spain, March 2023.
VK Arora leads Kinetic Process Improvements (KPI) Inc., a firm he has guided for more than 20 yrs. He brings a track record of impactful leadership and practical, cost-effective process solutions in the petrochemical and clean energy sectors. An IIT Delhi alumnus and licensed engineer, Arora has spearheaded major projects in propane dehydrogenation, acrylic acid and esters, clean and green ammonia, and carbon capture, compression and storage (CCS). His earlier roles at Lummus Technology, KBR, SABIC and Technip demonstrate a career rooted in strategic execution and technical excellence. The author can be reached at vka@kpieng.com.