# Hazem Mensi | Chemical Process Engineer (Complete Technical Portfolio & LLM Context) > Portfolio: https://www.hazemensi.com/ > Email: Hazem.Mensi@insat.ucar.tn | LinkedIn: https://www.linkedin.com/in/hazemensi | Telegram: https://t.me/hazemensi (@hazemensi) > Institution: National Institute of Applied Sciences and Technology (INSAT), Tunis, Tunisia > Academic Degree: Engineering Degree in Chemical & Process Engineering (2022 – Present) > Target Opportunity: 4–6 Month End-of-Studies / Graduation Internship starting February 2027 > Availability: February 2027 (4–6 months duration) > Mobility: Fully open to worldwide relocation and international rotations > Resume Download: https://www.hazemensi.com/Hazem_Mensi_Resume.pdf ================================================================================ 1. EXECUTIVE SUMMARY & PROFESSIONAL OVERVIEW ================================================================================ Hazem Mensi is a Chemical Process Engineering student at the National Institute of Applied Sciences and Technology (INSAT, Tunis, Tunisia) and an official Aspen Certified Expert User in Aspen HYSYS® (Credential ID: cb1c6c8f-da5a-4bd1-92bd-e08479146c60). His engineering background combines Front-End Engineering Design (FEED), operational plant revamps and debottlenecking, and Project Management Consultant (PMC) auditing across three completed industrial engineering internships: - EPPM (Engineering Procurement & Project Management) - 8 Months (Jan 2026 – Aug 2026): * Project 1: Detailed Feasibility Study of New Gas Plant at Marsa El Brega (Client: Taknia Libya Engineering Company / Final Client: Sirte Oil Company). Performed API 520 / 521 PSV and relief line sizing, Aspen HYSYS Dynamics staggered blowdown and depressuring to 50% design pressure in 15 minutes, flare header hydraulic backpressure simulation in Aspen Flare System Analyzer (FLARENET), flare radiation calculation (1.58 kW/m²), and shell-and-tube heat exchanger rating in Aspen EDR (HTFS). * Project 2: Naft Khana Oilfield Rehabilitation Detailed Engineering PMC (Iraq). Audited EPC contractor process design basis, equipment datasheets, and separator sizing against API 12J. Performed multiphase gathering line hydraulics in SLB PIPESIM, dynamic slugging and transient startup in HYSYS Dynamics, and topside slug catcher surge analysis. - Air Liquide - 2 Months (Jul 2025 – Aug 2025): Cryogenic Air Separation Unit (ASU) Direct Contact Heat Exchanger (DCHE) hydraulic revamp in Sulzer Sulcol, Koch-Glitsch KG-Tower, and Aspen Plus with high-performance packings (FLEXIPAC® HC® 2Y, MellapakPlus™ 252.Y, NeXRing™ 2), achieving an 85% pressure drop reduction and +35% flooding margin headroom. Managed industrial cooling water treatment and safety protocols. - OMV - 2 Months (Jun 2025 – Jul 2025): Front-End Engineering Design (FEED) for the Nawara CPF Amine Sweetening Tie-In serving 3 new production wells. Simulated Acid Gas Removal Units (AGRU) in BR&E ProMax and Aspen HYSYS, optimizing solvent to 40 wt% MDEA + 2 wt% piperazine, reducing treated gas CO₂ to 1.86 mol% (< 2.0 mol% pipeline spec), and lowering stripper reboiler duty to 3,500 kW at rich loading ≤ 0.45 mol CO₂/mol amine. ================================================================================ 2. CHRONOLOGICAL INDUSTRIAL INTERNSHIPS & DELIVERABLES ================================================================================ 1. EPPM (Engineering Procurement & Project Management) - Duration: Jan 2026 – Aug 2026 (8 months) - Location: Tunis, Tunisia (Hybrid) - Role: Process Engineering Intern (Relief Systems Designer & PMC Auditor) - Focus: EPC Detailed Engineering & PMC Technical Auditing - Project 1: Detailed Feasibility Study of New Gas Plant at Marsa El Brega (Libya) * Client: Taknia Libya Engineering Company (TLEC) · Final Client: Sirte Oil Company (SOC) * Scopes: API 520/521 safety valve sizing and inlet/outlet line hydraulics; Aspen HYSYS Dynamics staggered blowdown depressuring to 50% design pressure in 15 minutes; flare network backpressure analysis in Aspen Flare System Analyzer (FLARENET); flare stack height and thermal radiation modeling (1.58 kW/m² limit); Flare Knock-Out Drum (FKOD) sizing; heat exchanger rating in Aspen EDR (HTFS); Heat and Material Balances (H&MB) in HYSYS and Aspen Simulation Workbook (ASW); pump hydraulics and NPSH calculations. - Project 2: Naft Khana Oilfield Rehabilitation Detailed Engineering PMC (Iraq) * Scopes: Independent PMC technical audit of EPC contractor process design basis, equipment datasheets, and separator sizing against API 12J; multiphase gathering flowline hydraulics and line sizing in SLB PIPESIM; dynamic transient startup and hydrate dissociation boundary auditing in HYSYS Dynamics; topside slug catcher surge reception and liquid level control verification; issuance and management of formal Technical Queries (TQs) and discrepancy escalations. - Standards Applied: API 520 (Parts I & II), API 521 / ISO 23251, API 12J, API 14E, GPSA Engineering Data Book (Sec 5 & 7), TEMA, ASME Section VIII Division 1. - Tools Used: Aspen HYSYS Dynamics, Aspen HYSYS Steady-State, Aspen Flare System Analyzer (FLARENET), Aspen EDR, SLB PIPESIM, Aspen Simulation Workbook (ASW), Bluebeam Revu, Microsoft Excel. - Deliverables Produced: * Safety Relief Valve (PSV) Sizing Schedules & Line Sizing Check Sheets * Staggered Blowdown & Dynamic Depressuring Calculation Reports * FLARENET Header Hydraulic Verification & API 521 Flare Stack Radiation Study * Flare Knock-Out Drum (FKOD) & Heat Exchanger Process Datasheets * PMC Technical Audit Review Sheets on EPC Separator Calculations * Multiphase Flowline Pressure Profiles & Hydrate Mitigation Envelopes 2. Air Liquide - Duration: Jul 2025 – Aug 2025 (2 months) - Location: Ben Arous, Tunisia (On-site) - Role: Process Operations Engineering Intern - Focus: Cryogenic Air Separation Unit (ASU) Operations & Hydraulic Revamp - Scope: Direct Contact Heat Exchanger (DCHE) Column Retrofit & Industrial Operations * Modeled and evaluated hydraulic capacity and irrigated pressure drops in Sulzer Sulcol, Koch-Glitsch KG-Tower, and Aspen Plus across existing 2-inch random pall rings and high-performance packings (Koch-Glitsch FLEXIPAC® HC® 2Y, Sulzer MellapakPlus™ 252.Y, Sulzer NeXRing™ 2); achieved an 85% ΔP reduction and +35% flooding margin headroom; engineered multi-trough liquid distributor (>100 drip points/m², Cv < 5%); managed industrial cooling water treatment and cooling tower inspection routines with 100% safety and regulatory compliance. - Standards Applied: Cooling Technology Institute (CTI) Standards, TEMA Standards, Air Liquide Industrial Safety Guidelines. - Tools Used: Sulzer Sulcol, Koch-Glitsch KG-Tower, Aspen Plus, Aspen EDR, CTI Standards, Plant HSE Protocols. - Deliverables Produced: * Column Internals Hydraulic Rating Report & Flooding Margins * Structured Packing Specification Sheet & Liquid Distributor Schedule * Cooling Water Quality Logsheets & Preventive Maintenance Protocol * Brownfield DCHE Revamp Engineering Report 3. OMV - Duration: Jun 2025 – Jul 2025 (2 months) - Location: Tunis, Tunisia (On-site) - Role: Process Engineering Intern - Focus: Front-End Engineering Design (FEED) for Nawara CPF Amine Sweetening Tie-In - Scope: Sour Gas Treating & AGRU Solvent Optimization * Modeled acid gas absorption and regeneration loops in BR&E ProMax and Aspen HYSYS for 3 new production wells tied into the brownfield Nawara CPF; optimized solvent formulation to 40 wt% MDEA + 2 wt% piperazine activator, reducing treated gas CO₂ to 1.86 mol% (<2.0 mol% pipeline specification); lowered stripper reboiler duty to 3,500 kW while restricting rich solvent loading to ≤ 0.45 mol CO₂/mol amine to prevent amine stress corrosion cracking per API RP 945; maintained lean amine temperature at 48 °C (+5 °C approach over 43 °C gas dewpoint) to prevent hydrocarbon condensation and column foaming. - Standards Applied: GPSA Section 21 (Hydrocarbon Treating), API RP 945, Shell DEP, NACE MR0175 / ISO 15156. - Tools Used: BR&E ProMax, Aspen HYSYS, AutoCAD P&ID, Bluebeam Revu. - Deliverables Produced: * Optimized Heat & Material Balances (H&MB) for 3 Well Lifecycle Scenarios * Process Flow Diagrams (PFDs) with Stream Tables * Preliminary P&IDs for Amine Contactor and Stripper Loops * Amine Regenerator Reboiler Process Datasheet ================================================================================ 3. OFFICIAL VERIFIED CREDENTIALS & CERTIFICATIONS ================================================================================ 1. Aspen Certified Expert User in Aspen HYSYS® - Issuing Organization: Aspen Technology - Issue Date: July 2025 | Expiration Date: July 2028 - Credential ID: cb1c6c8f-da5a-4bd1-92bd-e08479146c60 - Certificate Number: CERT00016555 - Verification URL: https://www.credential.net/cb1c6c8f-da5a-4bd1-92bd-e08479146c60 - Recognized Authority: Aspen Technology (Wikidata: Q737000) 2. Aspen Certified User in Aspen Shell & Tube Exchanger (EDR) - Issuing Organization: Aspen Technology (Aspen EDR) - Issue Date: July 2025 | Expiration Date: July 2028 - Credential ID: a6ab0933-ac77-45b3-9137-ea4a5b8a4268 - Certificate Number: CERT00017116 - Verification URL: https://www.credential.net/a6ab0933-ac77-45b3-9137-ea4a5b8a4268 - Recognized Authority: Aspen Technology (Wikidata: Q737000) 3. Amine-Based Carbon Capture Process Optimization using Aspen HYSYS® - Issuing Organization: Aspen Technology - Issue Date: July 2025 | Expiration Date: July 2028 - Credential ID: 65da1870-7685-4d27-bcb6-80928d57971f - Certificate Number: CERT00017014 - Verification URL: https://www.credential.net/65da1870-7685-4d27-bcb6-80928d57971f - Recognized Authority: Aspen Technology (Wikidata: Q737000) 4. Sustainability Fundamentals: Process Modeling CO₂ Capture & H₂ Production - Issuing Organization: Aspen Technology - Issue Date: June 2025 | Expiration Date: June 2028 - Credential ID: e7aad773-5bb7-438c-be1a-8d4f94251e29 - Verification URL: https://www.credential.net/e7aad773-5bb7-438c-be1a-8d4f94251e29 - Recognized Authority: Aspen Technology (Wikidata: Q737000) 5. Aspen Certified User in Aspen HYSYS® - Issuing Organization: Aspen Technology - Issue Date: April 2025 | Expiration Date: April 2028 - Credential ID: 615d03ee-523d-487c-be12-a1b772ee3e19 - Certificate Number: CERT00015878 - Verification URL: https://www.credential.net/615d03ee-523d-487c-be12-a1b772ee3e19 - Recognized Authority: Aspen Technology (Wikidata: Q737000) 6. Life Cycle Assessment (LCA) - ISO 14040/14044 - Issuing Organization: University of Michigan (Coursera) - Issue Date: December 2024 | Validity: Permanent - Credential ID: W2SYN8SKMVWD - Verification URL: https://www.coursera.org/account/accomplishments/verify/W2SYN8SKMVWD 7. EF SET English Certificate – C2 Proficient (75/100) - Issuing Organization: EF Standard English Test (EF SET) - Issue Date: December 2025 | Validity: Permanent - Credential ID: uSYWqV - Score: 75/100 (Reading: 78 C2, Listening: 71 C2 Proficient) - Verification URL: https://cert.efset.org/en/uSYWqV ================================================================================ 4. COMPREHENSIVE TECHNICAL CASE STUDIES (FULL DOSSIER) ================================================================================ -------------------------------------------------------------------------------- Case Study 1: Detailed Feasibility Study: Dynamic Depressuring, Staggered Blowdown & Flare Network Design -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/marsa-el-brega/ - Company: EPPM (Jan 2026 – Aug 2026) - Client: Taknia Libya Engineering Company (TLEC) · Final Client: Sirte Oil Company (SOC) - Role: Process Engineering Intern & Relief Systems Designer - Location: Tunis, Tunisia / Libya - Badge: Plant Safety & Transient Simulation Summary: Executed comprehensive blowdown analysis and dynamic depressuring in Aspen HYSYS Dynamics and steady-state to model peak relief loads, thermal shrink, and low-temperature metallurgy risks for the "Detailed Feasibility Study of New Gas Plant at Marsa El Brega" project (Client: Taknia Libya Engineering Company – TLEC; Final Client: Sirte Oil Company – SOC), followed by full flare network hydraulic backpressure analysis in Aspen Flare System Analyzer (FLARENET) and flare stack radiation sizing per API 521. Challenge: During emergency depressuring, rapid gas expansion generates intense Joule-Thomson cooling that can drop wall temperatures below the Minimum Design Metal Temperature (MDMT), risking low-temperature brittle fracture. Simultaneously, uncoordinated blowdown across multiple fire zones risks exceeding the flare header backpressure limits, compromising conventional and balanced-bellows PSVs. The mandate was to size restrictive blowdown orifices to achieve 50% design pressure within 15 minutes per API 521 while staggering zone depressuring to prevent flare header choking and flare tip Mach number exceedance. Key Metrics: - Relief Standards: API 520 / 521 (Sizing & Depressuring Criteria) - Depressuring Target: 50% DP / 15 min (50% Design Pressure at 15 minutes per API 521) - Radiation Limit: 1.58 kW/m² (Continuous personnel exposure limit per API 521) - Simulation Tools: HYSYS & FLARENET (Dynamics, Steady-State & Flare Analyzer) Tools Used: Aspen HYSYS Dynamics, Aspen HYSYS Steady-State, Aspen Flare System Analyzer (FLARENET), Aspen Simulation Workbook (ASW), Microsoft Excel. Standards Applied: API 521 (Pressure-relieving and Depressuring Systems), API 520 Part I & II, GPSA Engineering Data Book Sec 5. Simulation Methodology: Simulated transient emergency depressuring across high-pressure gas processing systems in Aspen HYSYS Dynamics and Flare System Analyzer (FLARENET) using the Peng-Robinson Equation of State (PR-EOS) with Boston-Mathias alpha formulations. Calculated real-fluid vapor-liquid equilibrium (VLE) and Joule-Thomson expansion cooling coefficients across severe pressure drops from 85 barg operating pressure down to 1.2 barg flare header conditions. Modeled dynamic conductive heat transfer through carbon steel vessel walls (25–50 mm ASTM A516 Gr 70) and external fire heat flux per API 521 guidelines (q = 43,200 · F · Aw^0.82 kJ/h). Sized restrictive blowdown orifices (RO) to satisfy API 521 depressuring criteria—reducing system inventory pressure to 50% of design pressure within 15 minutes—while evaluating low-temperature embrittlement risks. The dynamic thermal models accounted for wetted and unwetted internal surface areas, liquid holdup vaporization, and heat transfer from vessel steel mass, providing exact transient thermal profiles for safety valve sizing and header backpressure auditing against API 520 limits. Engineering Trade-Offs: Isenthalpic expansion across blowdown orifices drops fluid temperatures below -38 °C, creating low-temperature brittle fracture risks if metal walls fall below the -29 °C Minimum Design Metal Temperature (MDMT) per ASME Section VIII UCS-66. Dynamic heat transfer simulation proved that vessel wall thermal inertia delays metal chilling, maintaining the inner wall above -25 °C during the critical 15-minute blowdown window and avoiding costly stainless steel metallurgical upgrades. Simultaneous blowdown of all process zones would discharge over 320 t/h of gas, choking common flare sub-headers (Mach ≥ 1.0), triggering acoustic-induced vibration (ρv² > 200,000 kg/(m·s²)), and derating conventional relief valves through excessive built-up backpressure. Engineering a 3-zone staggered depressuring sequence (Zone 1 at t = 0, Zone 2 at t = 5 min, Zone 3 at t = 10 min) flattened aggregate relief loads, holding header velocities below Mach 0.5, flare tip exit velocity below Mach 0.7, and personnel thermal radiation below 1.58 kW/m² per API 521. Technical FAQs: Q1: How does staggered blowdown prevent flare header acoustic fatigue and sonic choking during emergency depressuring? A1: Staggered blowdown sequences depressuring across isolated plant fire zones at 5- to 10-minute intervals rather than venting all units simultaneously. This offsets the initial sonic relief peaks that occur within the first 180 seconds of blowdown valve opening. In Aspen HYSYS Dynamics and FLARENET, staggered scheduling holds sub-header velocities below Mach 0.5 and flare tip exit velocity below Mach 0.7, suppressing acoustic-induced vibration (ρv² < 200,000 kg/(m·s²)) and preventing pipe fatigue failure. Q2: Why is Joule-Thomson cooling a critical constraint in sizing API 521 depressuring orifices? A2: Rapid gas expansion across a depressuring orifice induces intense Joule-Thomson cooling, dropping natural gas temperatures below -35 °C. If the chilled fluid drops the vessel wall below its -29 °C MDMT per ASME Section VIII UCS-66, brittle fracture can occur under residual pressure. Dynamic simulation verifies that orifices achieve 50% depressuring in 15 minutes per API 521 while vessel thermal inertia prevents metal wall temperatures from breaching the MDMT limit. Q3: How does backpressure in FLARENET impact the selection between conventional and balanced-bellows PSVs? A3: Built-up backpressure in a flare header opposes the opening disk of a conventional relief valve. Per API 520, conventional PSVs are limited to 10% maximum built-up backpressure before chattering and capacity derating occur. Where FLARENET models show peak backpressures reaching 25% to 40% of set pressure during multi-zone flaring, balanced-bellows PSVs or pilot-operated valves must be specified to isolate the disk from downstream backpressure and guarantee full relief capacity. -------------------------------------------------------------------------------- Case Study 2: Nawara CPF Brownfield Amine Sweetening Tie-In & AGRU Solvent Optimization -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/agru-optimization/ - Company: OMV (Jun 2025 – Jul 2025) - Role: Process Engineering Intern - Location: Tunis, Tunisia - Badge: Gas Treating & Thermodynamics Summary: On the Amine Sweetening Tie-In project at the brownfield Nawara CPF (internal asset operations), executed core process simulation and optimization for an Acid Gas Removal Unit (AGRU) treating sour natural gas from 3 new production wells. Benchmarked solvent kinetics and thermodynamic packages in BR&E ProMax and Aspen HYSYS, achieving 1.86 mol% CO₂ in treated gas while reducing stripper reboiler duty to 3,500 kW under strict transmission pipeline delivery constraints. Challenge: At the brownfield Nawara Central Processing Facility (CPF), raw feed gas from 3 new production wells contained elevated CO₂ concentrations exceeding sales gas pipeline specifications (< 2.0 mol%). The engineering mandate was to minimize regenerator reboiler thermal duty to 3,500 kW while maintaining rich solvent loading within the corrosion safety envelope (≤ 0.45 mol CO₂/mol amine), avoiding thermal/oxidative degradation of the MDEA/piperazine solvent blend, and satisfying transmission pipeline delivery constraints and Wobbe index limits under fluctuating wellhead pressures. Key Metrics: - Treated CO₂ Spec: 1.86 mol% (Met pipeline transmission spec < 2.0 mol%) - Reboiler Duty: 3,500 kW (Optimized regeneration heat requirement) - Solvent Formulation: 40 wt% MDEA (+ 2 wt% Piperazine Activator) - Rich Loading: ≤ 0.45 mol/mol (Corrosion safety envelope ≤ 0.45 mol CO₂/mol amine) Tools Used: BR&E ProMax, Aspen HYSYS, AutoCAD P&ID, Bluebeam Revu. Standards Applied: GPSA Section 21 (Hydrocarbon Treating), API RP 945, Shell DEP & NACE MR0175 / ISO 15156. Simulation Methodology: Modeled gas treating kinetics and electrolyte thermodynamics in BR&E ProMax and Aspen HYSYS using rigorous Electrolytic Chemical Solvents property packages. Simulated vapor-liquid equilibrium (VLE), chemical reaction kinetics, and liquid-phase ionic speciation (MDEAH⁺, HCO₃⁻, PZCOO⁻, PZ(COO)₂²⁻) across a 24-tray high-pressure absorber operating at 72 barg and a 20-tray regenerator stripper operating at 1.8 barg. Evaluated mass transfer rates, column hydraulic flooding curves, and weeping limits per GPSA Engineering Data Book Section 21 and Shell DEP specifications. Chemical solvent circulation rates, rich-lean heat exchanger pinch profiles, and condenser reflux dynamics were benchmarked to guarantee that treated sales gas reliably satisfied transmission pipeline delivery specifications (< 2.0 mol% CO₂) under fluctuating sour feed gas compositions from 3 new production wells while adhering to NACE MR0175 / ISO 15156 and API RP 945 material corrosion envelopes. Engineering Trade-Offs: Unpromoted tertiary MDEA exhibits low regeneration energy (~1,150 kJ/kg CO₂) but slow CO₂ hydration kinetics. Activating 40 wt% MDEA with 2 wt% piperazine introduced a fast kinetic shuttle, forming rapid carbamate intermediates that accelerated CO₂ mass transfer. This achieved 1.86 mol% CO₂ in treated sales gas while avoiding larger absorber column diameters or additional tray additions. Stripper reboiler thermal duty was reduced to 3,500 kW by optimizing rich/lean cross-exchanger heat recovery and tuning the steam-to-acid-gas stripping ratio to 1.1 mol/mol. To prevent amine stress corrosion cracking (ASCC) and uniform corrosion per API RP 945, rich solvent loading was strictly capped at ≤ 0.45 mol CO₂/mol amine. In parallel, lean amine temperature was maintained at 48 °C—exactly 5 °C above the 43 °C feed gas dewpoint—preventing hydrocarbon condensation and catastrophic absorber foaming. Technical FAQs: Q1: How does adding 2 wt% piperazine to 40 wt% MDEA reduce regenerator reboiler duty? A1: MDEA has a low heat of regeneration (~1,150 kJ/kg CO₂) but slow CO₂ absorption kinetics. Piperazine acts as a kinetic promoter that rapidly forms carbamate intermediates, accelerating mass transfer in the absorber. By activating 40 wt% MDEA with 2 wt% piperazine, the required solvent circulation rate is reduced while achieving 1.86 mol% CO₂ in treated gas. Slower circulation reduces sensible heat loads on the regenerator reboiler, cutting thermal duty to 3,500 kW. Q2: Why must rich amine loading be capped at 0.45 mol CO₂/mol amine in carbon steel systems? A2: At rich loading levels above 0.45 mol CO₂/mol amine, unreacted aqueous CO₂ forms highly corrosive carbonic acid that strips the protective iron carbonate (FeCO₃) layer from carbon steel per API RP 945. This triggers severe erosion-corrosion downstream of the absorber level control valve and throughout rich/lean exchangers. Capping loading at ≤ 0.45 mol/mol keeps corrosion rates below 0.1 mm/year, avoiding expensive stainless steel upgrades. Q3: How does maintaining a +5 °C temperature approach on lean amine prevent absorber foaming? A3: Raw natural gas enters the absorber saturated with heavy hydrocarbons (C₅+). If incoming lean amine is colder than the feed gas dewpoint, hydrocarbons condense into liquid droplets within the solvent. Liquid hydrocarbons drastically depress surface tension, creating stable foam that bridges trays and triggers rapid column flooding. Maintaining lean amine 5 °C hotter than the feed gas ensures vapor remains superheated, completely preventing condensation and foam formation. -------------------------------------------------------------------------------- Case Study 3: Direct Contact Heat Exchanger (DCHE) Retrofit & Cooling Systems -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/dche-retrofit/ - Company: Air Liquide (Jul 2025 – Aug 2025) - Role: Process Operations Engineering Intern - Location: Ben Arous, Tunisia - Badge: Equipment Retrofit & Hydraulics Summary: Spearheaded the hydraulic evaluation and column internals revamp of a direct contact heat exchanger in an industrial cryogenic cooling unit (internal operations). Modeled and benchmarked high-performance structured and advanced random packings in Sulzer Sulcol, Koch-Glitsch KG-Tower, and Aspen Plus, achieving an 85% pressure drop reduction, maximized flooding margins, and expanded hydraulic throughput capacity. Challenge: The existing direct contact cooling column utilized conventional random packing that generated excessive hydraulic pressure drop and liquid maldistribution under peak summer ambient temperatures, creating an upstream compressor suction bottleneck. The technical challenge was to proactively revamp the column internals to achieve superior pressure drop reduction and expand throughput capacity without expensive vessel shell modifications. By rigorously modeling and benchmarking high-performance structured and modern random packings—specifically Koch-Glitsch FLEXIPAC® HC® 2Y metal, Sulzer MellapakPlus™ 252.Y metal, and Sulzer NeXRing™ 2 metal—I successfully engineered a retrofit solution that delivered an 85% ΔP reduction, maximized flooding margins, and increased gas throughput potential while preserving the required thermal approach. Key Metrics: - Pressure Drop ΔP: -85% (dP) (Achieved via Modern Internals Revamp) - Packings Evaluated: High-Perf Metals (FLEXIPAC® HC 2Y, MellapakPlus™, NeXRing™) - Flooding Margin: +35% (Hydraulic capacity headroom above flood point) - Modeling Software: Sulcol / KG-Tower (+ Aspen Plus Hydraulic Rating) Tools Used: Sulzer Sulcol, Koch-Glitsch KG-Tower, Aspen Plus, Aspen EDR, FLEXIPAC® HC 2Y, MellapakPlus™ 252.Y, NeXRing™ 2. Standards Applied: Cooling Technology Institute (CTI) Standards, TEMA Standards, Air Liquide Safety Protocols. Simulation Methodology: Evaluated column hydraulic capacity and irrigated pressure drop profiles using Sulzer Sulcol and Koch-Glitsch KG-Tower software, cross-verified with Aspen Plus hydraulic rating models. Benchmarked generalized pressure drop correlations (GPDC) and vendor-specific packing factors across existing 2-inch random pall rings (Fp ≈ 85 m⁻¹) and advanced high-capacity packings: Koch-Glitsch FLEXIPAC® HC® 2Y (Fp ≈ 22 m⁻¹), Sulzer MellapakPlus™ 252.Y (Fp ≈ 24 m⁻¹), and Sulzer NeXRing™ 2 (Fp ≈ 42 m⁻¹). Rigorous mass and heat transfer models evaluated vapor-liquid countercurrent contact dynamics, effective surface area utilization, and irrigated liquid holdup under peak summer air intake temperatures. Hydraulic limits, entrainment thresholds, and flooding margins were analyzed in accordance with Cooling Technology Institute (CTI) standards and Air Liquide cryogenic oxygen-service process safety protocols to safeguard downstream main air compressor suction performance. Engineering Trade-Offs: Under peak summer ambient conditions, high cooling water temperatures drove existing random pall rings near their hydraulic flooding limit, generating a 30 mbar pressure drop that penalized the suction of the main air compressor (MAC). Revamping column internals with Sulzer MellapakPlus™ 252.Y and FLEXIPAC® HC® 2Y structured packings slashed bed pressure drop by 85% (< 4.5 mbar), eliminating compressor throttling and expanding hydraulic flooding margin headroom by +35%. To preserve the tight cryogenic thermal approach (Tgas,out - Twater,in ≤ 1.8 °C), high specific surface area (250 m²/m³) was maintained without increasing bed height. Because structured packings lack radial liquid spreading, a high-efficiency multi-trough distributor delivering > 100 drip points/m² with a maldistribution coefficient of variation (Cv < 5%) was engineered, preventing dry zones, liquid wall channeling, and loss of effective heat transfer area. Technical FAQs: Q1: How does structured packing achieve an 85% pressure drop reduction compared to conventional random packing? A1: Conventional random packings create tortuous flow paths with high form drag and packing factors (Fp) between 80 and 100 m⁻¹. Structured packings, such as Sulzer MellapakPlus™ 252.Y and FLEXIPAC® HC® 2Y, use corrugated metal sheets arranged in alternating parallel orientations with smooth crimp transitions. This geometry yields void fractions over 97% and cuts packing factors to 22–28 m⁻¹, eliminating recirculating eddies and reducing irrigated pressure drop by 85%. Q2: What determines the flooding margin in a cryogenic Direct Contact Heat Exchanger? A2: Flooding margin represents operating headroom before reaching the hydraulic flooding limit, calculated using capacity factor Cs = vG · √(ρG / (ρL - ρG)) and flow parameter X = (L/G) · √(ρG / ρL). In DCHEs at high gas velocities, vapor drag forces prevent liquid drainage, causing entrainment. Revamping to MellapakPlus™ 252.Y raises the hydraulic flood line, expanding operational flooding margin by +35% and allowing higher seasonal throughput without liquid carryover. Q3: Why is liquid distributor design critical when revamping from random to structured column internals? A3: Structured packings rely on thin liquid films flowing along corrugated sheets and lack natural radial redistribution. Initial maldistribution causes dry zones and vapor channeling, collapsing the volumetric heat transfer coefficient (Uv·a) and widening thermal approach. Installing a multi-trough distributor with calibrated orifices providing over 100 drip points/m² and a coefficient of variation (Cv) below 5% ensures complete surface wetting and guarantees designed heat transfer performance. -------------------------------------------------------------------------------- Case Study 4: Multiphase Flowline Hydraulics, Slugging & Hydrate Transient Study -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/naft-khana-flowline/ - Company: EPPM (Jan 2026 – Aug 2026) - Client: PMC Project · Naft Khana Oilfield Rehabilitation (Iraq) - Role: Process Engineering Intern (PMC) - Location: Middle East / Iraq - Badge: Flow Assurance & PMC Auditing Summary: Served as process engineer on the Project Management Consultant (PMC) team for the Naft Khana Oilfield Rehabilitation project, executing rigorous technical review and auditing of the EPC engineering firm's design calculations, equipment sizing books, and flow assurance models. Independently validated multiphase gathering hydraulics in SLB PIPESIM, topside slug catcher dynamic surge response in Aspen HYSYS Dynamics, and chemical hydrate mitigation envelopes. Challenge: Serving as process engineer on the PMC team required critically auditing the EPC engineering contractor's calculation books, simulation assumptions, and equipment specifications across an undulating gathering network. The challenge was to independently verify whether the contractor's steady-state sizing adequately accounted for hydrodynamic and terrain-induced slugging at turndown rates, cold restart risks within the hydrate formation zone, and severe liquid surges during pigging operations. Through rigorous technical audit of separator sizing calculations (API 12J / GPSA) and steady-state hydraulic modeling in PIPESIM with topside slug catcher surge verification in HYSYS Dynamics, I identified key discrepancies in contractor liquid retention assumptions and inhibitor injection rates, issuing formal Technical Queries (TQs) to safeguard downstream processing facilities. Key Metrics: - PMC Scope: EPC Design Audit (Calculation & Assumption Verification) - Flow Assurance: PIPESIM & HYSYS (Multiphase Hydraulics & Slugging) - Design Audit: API 12J & 14E (Separator & Flowline Sizing Review) - Hydrate Strategy: Thermodynamic (Inhibitor Dosage & Subcooling Check) Tools Used: SLB PIPESIM, Aspen HYSYS Upstream, HYSYS Dynamics, Bluebeam Revu. Standards Applied: API 14E (Design of Piping Systems), API 12J (Separators), ISO 13703, GPSA Sec 7. Simulation Methodology: Executed independent PMC technical audits of EPC contractor flow assurance deliverables using SLB PIPESIM for multiphase gathering hydraulics (revised Beggs-Brill and mechanistic models) across undulating 8-inch and 10-inch flowlines. Audited topside finger-type slug catcher dynamic surge capacities in Aspen HYSYS Dynamics during production ramp-up, transient flow transitions, and pigging operations. Validated two-phase and three-phase production separator sizing against API 12J droplet settling criteria (Souders-Brown vapor velocity limits and liquid retention times). Audited erosional velocity ceilings per API 14E (ve = c / √ρmix) and established hydrate thermodynamic formation dissociation boundaries using ISO 13703 and GPSA Section 7 standards to verify continuous chemical inhibitor dosage across all operating envelopes. Engineering Trade-Offs: The EPC contractor sized gathering lines based on nominal steady-state throughput, predicting stable stratified flow and specifying an undersized 15 m³ slug catcher. PMC independent modeling revealed that at 50% turndown, low gas velocities allowed liquid to pool in downhill valleys, triggering severe terrain-induced slugging with slug volumes exceeding 35 m³ upon rate increases. PMC issued formal Technical Queries (TQs) mandating an expanded slug catcher capacity of 45 m³ and upgraded LCV trim to safeguard downstream units from high-level tripping. To balance pipe sizing, fluid mixture velocities were constrained between the minimum sweeping velocity (3.5 m/s) to suppress liquid dropout and the API 14E erosional velocity ceiling (13 m/s). For hydrate mitigation, PMC discovered contractor calculation errors under winter conditions (4 °C ambient, 80 barg), mandating corrected continuous Monoethylene Glycol (MEG) dosing to maintain a 3 °C safety margin below depressed hydrate formation temperatures. Technical FAQs: Q1: How does terrain-induced slugging differ from hydrodynamic slugging in undulating flowlines? A1: Hydrodynamic slugging forms spontaneously in flat pipes due to Kelvin-Helmholtz instabilities where fast gas waves bridge the pipe cross-section. Terrain-induced slugging occurs in undulating topography: liquid settles in low elevation valleys during turndown flow until upstream gas pressure builds sufficiently to blow the liquid pocket up the incline as a concentrated slug. Terrain slugs are much larger than hydrodynamic slugs, requiring dynamic transient modeling in PIPESIM to determine slug catcher surge capacity. Q2: How is separator sizing audited against API 12J droplet settling criteria? A2: API 12J sizing audits calculate gas capacity using terminal settling velocity from the Souders-Brown equation vmax = K · √((ρL - ρG)/ρG), where the empirical K-factor is selected based on mesh pad geometry (0.07–0.12 m/s). Liquid retention volume is audited against oil-water separation kinetics, enforcing 3 to 5 minutes retention time between Low Liquid Level (LLL) and High Liquid Level (HLL) to prevent gas blowby and guarantee 100-micron droplet knockout. Q3: Why must the API 14E erosional velocity limit be balanced against liquid holdup accumulation? A3: API 14E establishes maximum fluid velocity as ve = c / √ρmix (c = 100) to prevent pipe wall erosion from particulate impingement. However, oversizing flowlines to lower velocity drops shear stress below critical levels, allowing liquid to drop out and form severe terrain slugs that accelerate bottom-of-line corrosion. Diameter selection must balance mixture velocity between minimum sweeping speed (3–4 m/s) and the erosional ceiling (12–14 m/s). -------------------------------------------------------------------------------- Case Study 5: Techno-Economic Assessment: SMR with Carbon Capture vs. Alkaline Water Electrolysis -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/hydrogen-techno-economic/ - Institution: INSAT Research Initiative (Jan 2025 – May 2025) - Role: Process Engineering Researcher - Location: Tunis, Tunisia - Badge: Energy Transition & Decarbonization Summary: Conducted a comparative techno-economic assessment (TEA) of industrial hydrogen production via Steam Methane Reforming (SMR) integrated with Carbon Capture and Storage (CCS) vs. Alkaline Water Electrolysis (AWE). Focused on Aspen HYSYS flowsheet simulation, primary reformer equilibrium, pre- and post-combustion heat integration, steam-to-carbon ratio optimization, and Microsoft Excel capital/operational expenditure modeling. Challenge: Achieving deep decarbonization (> 95% total CO₂ capture) in Steam Methane Reforming without imposing prohibitive energy penalties or levelized cost escalation. The technical challenge required optimizing the reformer reaction equilibrium and steam-to-carbon ratio (S/C: 2.5–3.0) to prevent catalyst coking, while maximizing waste heat recovery across syngas effluent and flue gas convection coils to supply the thermal regeneration duty of the amine-based CO₂ capture unit. By integrating Aspen HYSYS flowsheet simulation with capital and operational cost models in Microsoft Excel, I evaluated the trade-offs between SMR + CCS heat integration and renewable-powered alkaline electrolysis under real-world industrial utility and economic constraints. Key Metrics: - Carbon Capture: > 95% (Deep SMR + CCS Decarbonization) - Steam-to-Carbon Ratio (S/C): S/C: 2.5–3.0 (Catalyst Coking Suppression Envelope) - Heat Integration: Waste Heat Rec. (Syngas & Flue Gas to Capture Reboiler) - Economic Modeling: Microsoft Excel (Discounted Cash Flow TEA CAPEX/OPEX) Tools Used: Aspen HYSYS, Microsoft Excel, Flowsheet Material & Energy Balances, TEA Workbooks. Standards Applied: ISO 14040/14044 (Life Cycle Assessment), GPSA Section 21, IEA Greenhouse Gas R&D Guidelines. Simulation Methodology: Simulated industrial hydrogen production (100,000 Nm³/h) in Aspen HYSYS using the Peng-Robinson EOS with Lee-Kesler enthalpy formulations for high-temperature syngas and Electrolyte-NRTL for amine-based CO₂ capture. Modeled primary steam methane reforming via Gibbs free energy minimization (T = 880 °C, P = 28 bar) coupled with high-temperature (380 °C) and low-temperature (210 °C) water-gas shift catalytic reactors. Developed a comprehensive 25-year Discounted Cash Flow (DCF) techno-economic model in Microsoft Excel to calculate Levelized Cost of Hydrogen (LCOH, $/kg H₂) per IEA Greenhouse Gas (IEAGHG) R&D Guidelines and ISO 14040/14044 Life Cycle Assessment carbon accounting standards. Evaluated capital expenditures (CAPEX), operating expenditures (OPEX), stack replacement schedules, and electrical utility tariffs across sensitivity matrices. Engineering Trade-Offs: Operating the primary reformer at a steam-to-carbon ratio (S/C) between 2.5 and 3.0 provides steam partial pressure to suppress catalyst coking via methane cracking (CH₄ → C + 2H₂) and Boudouard reactions (2CO → C + CO₂). An optimized S/C ratio of 2.8 prevented carbon deactivation while limiting boiler fuel consumption. Reaching deep >95% carbon capture required dual amine absorption units treating both high-pressure syngas and atmospheric reformer flue gas, demanding substantial thermal regeneration duty (3.2 MJ/kg CO₂). Through dual-stage pinch heat integration, sensible heat from 880 °C syngas effluent and convection flue gas (950 °C down to 160 °C) was recovered to raise stripping steam, supplying 82% of reboiler duty internally. SMR+CCS yielded an LCOH of $2.10–$2.65/kg H₂, whereas Alkaline Water Electrolysis (consuming 52 kWh/kg H₂) achieved cost parity only when renewable electricity dropped below $30/MWh at >65% capacity factor. Technical FAQs: Q1: Why is a Steam-to-Carbon (S/C) ratio of 2.5–3.0 required in primary steam methane reforming? A1: The steam-to-carbon ratio (S/C) establishes chemical equilibrium between reforming, water-gas shift, and carbon-forming reactions. Maintaining S/C between 2.5 and 3.0 provides sufficient steam partial pressure to prevent catalyst deactivation caused by methane cracking (CH₄ → C + 2H₂) and the Boudouard reaction (2CO → C + CO₂). Ratios below 2.2 risk rapid carbon filament growth, creating tube hot spots, catalyst fracture, and premature tube rupture at 880 °C. Q2: How does dual-stage waste heat integration enable >95% total CO₂ capture in SMR plants? A2: In SMR, ~60% of CO₂ is in high-pressure syngas and ~40% is in atmospheric combustion flue gas. Capturing >95% total CO₂ requires solvent absorption on both streams, which demands significant reboiler energy (3.0–3.5 MJ/kg CO₂). Through dual-stage pinch heat recovery, sensible heat from 880 °C syngas effluent and flue gas convection coils is recovered to raise low-pressure stripping steam. This meets over 80% of reboiler duty internally, avoiding fuel consumption escalation. Q3: At what electricity price does Alkaline Water Electrolysis (AWE) become cost-competitive with SMR + CCS? A3: Alkaline water electrolysis consumes 50–55 kWh of electrical power per kilogram of hydrogen, making electricity over 70% of its LCOH. SMR with carbon capture produces hydrogen at $2.10–$2.65/kg H₂ with natural gas at $6/MMBtu. Alkaline electrolysis achieves cost parity with SMR+CCS only when delivered renewable electricity drops below $28–$32/MWh with an electrolyzer utilization factor exceeding 65% (> 5,700 full-load operating hours annually). -------------------------------------------------------------------------------- Case Study 6: Process Engineering Automation & Deliverable Generator -------------------------------------------------------------------------------- - Canonical URL: https://www.hazemensi.com/case-studies/process-automation-platform/ - Initiative: Engineering Innovation (2026) - Role: Process Systems Developer - Location: Tunis, Tunisia - Badge: Digital Process Automation Summary: Developed automated process calculation and deliverable generation modules in Python and Microsoft Excel to eliminate manual transcription from simulation flowsheets. Automated equipment sizing, rating checks, and datasheet generation for safety relief valves (API 520 / 521), two-phase separators (API 12J), and centrifugal pump hydraulic calculations (TDH, NPSHa margins, and process datasheet preparation aligned with API 610 / Shell DEP formats). Challenge: Process engineers spend excessive hours manually copying stream data and thermodynamic properties from Aspen HYSYS into separate Excel calculation spreadsheets, introducing transcription errors and slowing down deliverable turnaround during tight EPC and FEED schedules. Key Metrics: - Turnaround Time: 10x Faster (Automated Equipment Sizing & Checks) - Safety Relief: API 520 / 521 (Programmed PSV Sizing Equations) - Separators & Pumps: API 12J & 610 (Vessel Rating & Pump Hydraulics) - Core Tools: Python & Excel (Automated Engineering Workbooks) Tools Used: Python, Microsoft Excel, Aspen Simulation Workbook (ASW), OpenPyXL / Automation Scripts, Engineering Calculation Sheets. Standards Applied: API 520 Parts I & II (Relief Sizing), API 521 (Depressuring Systems), API 12J (Oil & Gas Separators), API 610 (Centrifugal Pumps), Shell DEP Standards. Simulation Methodology: Architected a modular process engineering calculation engine using Python (NumPy, pandas, openpyxl) integrated with Microsoft Excel and Aspen Simulation Workbook (ASW) via COM automation. The framework extracts thermodynamic fluid properties (compressibility Z, vapor density ρv, liquid density ρl, dynamic viscosity μ, and isentropic expansion coefficient k = Cp/Cv) directly from Aspen HYSYS process simulations into automated design workbooks without manual data entry. Programmed rigorous sizing algorithms per API 520 Part I & II (10th Edition) for gas, liquid, steam, and two-phase flashing relief scenarios, incorporating backpressure derating factors (Kb, Kw) and discharge coefficient corrections (Kd). Integrated API 12J standards for horizontal and vertical gas-liquid separators, determining droplet settling criteria and retention volumes. Encoded API 610 (12th Edition) and Shell DEP standards for centrifugal pump hydraulics, automating Total Dynamic Head (TDH), system resistance head curves, Net Positive Suction Head Available (NPSHa), and suction specific speed (Nss) ratings. Engineering Trade-Offs: API 520 calculations yield theoretical effective relief areas (Acalc). Selecting the next standard API 526 commercial orifice designation (letters D through T) frequently introduces excessive oversizing (Aselected > 1.30 · Acalc). The automated engine calculates rated relieving capacity against required mass flow, systematically flagging oversizing factors exceeding 25% to prevent relief valve chattering, rapid seat galling, mechanical fatigue, and downstream flare header pressure spikes, recommending dual-staggered relief valves or split-range configurations where necessary. For gas-liquid separator geometry, the algorithm iterates through standard ASME Section VIII Division 1 vessel shell and head dimensions to optimize length-to-diameter (L/D) ratios between 2.5:1 and 4.5:1. This balances vessel steel mass minimization against Souders-Brown vapor velocity limits (K = 0.07–0.12 m/s) and liquid surge residence times (3 to 5 minutes between low and high liquid levels). In centrifugal pump hydraulics, suction line piping was iteratively sized to constrain liquid velocity within 1.0 m/s to 1.8 m/s per Shell DEP while enforcing a minimum NPSH margin of 1.0 m (or 20% above NPSHr) and capping suction specific speed (Nss ≤ 11,000) to prevent acoustic cavitation, internal recirculation, and premature seal failure. Technical FAQs: Q1: How does automated API 520 sizing prevent relief valve chattering caused by excessive oversizing? A1: Relief valves are manufactured in discrete API 526 standard orifice sizes (D through T). When a chosen standard orifice area exceeds the calculated requirement by more than 25% (Aselected > 1.25 · Acalc), the valve relieves vapor faster than the upstream process generates it. This causes upstream pressure to rapidly collapse below reseat pressure, inducing violent, high-frequency valve chattering that damages valve seats and bellows. The automation algorithm computes rated capacity, flags excessive oversizing, and recommends staggered dual-valve configurations. Q2: How does the algorithm optimize separator length-to-diameter (L/D) ratios for minimum vessel weight? A2: The separator sizing module couples API 12J droplet settling equations with ASME Section VIII Division 1 shell wall thickness calculations. By sweeping across nominal vessel diameters in 2-inch increments, it evaluates required seam-to-seam length to simultaneously satisfy Souders-Brown vapor disengagement (K = 0.07–0.12 m/s) and liquid surge holdup (3 to 5 minutes retention time). Evaluating vessel steel tonnage across L/D ratios between 2.5:1 and 4.5:1 reveals the exact geometry that minimizes fabrication cost while meeting process guarantees. Q3: Why is suction specific speed (Nss) a critical constraint in automated pump hydraulic calculations? A3: Suction specific speed (Nss = N · √Q / NPSHr^0.75) characterizes the suction geometry and inlet eye diameter of a pump impeller. While high Nss impellers (Nss > 11,000 in US customary units) offer lower NPSH requirements, they exhibit severe internal suction recirculation, acoustic pressure pulsations, and impeller erosion when operating below best efficiency point (BEP). The platform audits pump selections against API 610 and Shell DEP, enforcing Nss ≤ 11,000 and verifying NPSHa margins of at least 1.0 m across all continuous operating ranges. ================================================================================ 5. TECHNICAL COMPETENCIES, SOFTWARE & STANDARDS ================================================================================ - Process Simulation & Flow Assurance: Aspen HYSYS (Steady-State & Dynamics), BR&E ProMax, Aspen Plus, PetroSim, SLB PIPESIM, OLGA, Aspen Flare System Analyzer (FLARENET), AFT Fathom, AFT Impulse. - Equipment Rating & Thermal Design: Aspen EDR (HTFS), HTRI Xchanger Suite, Sulzer Sulcol, Koch-Glitsch KG-Tower, Separator & Knock-Out Drum Sizing (API 12J / API 521), Centrifugal Pump Hydraulics & NPSH. - Codes & International Standards: API 520 (Parts I & II), API 521 / ISO 23251, API 12J, API 14E, API STD 2000, API 610, ASME Section VIII Div 1, ASME B31.3, Shell DEP, GPSA Engineering Data Book, TEMA, ISO 14040/14044, NACE MR0175 / ISO 15156. - Engineering Computing & Drafting: Python, OpenPyXL, Aspen Simulation Workbook (ASW), AutoCAD P&ID, Bluebeam Revu, Microsoft Excel Engineering Workbooks, Git/GitHub. ================================================================================ 6. ACADEMIC CURRICULUM AT INSAT ================================================================================ National Institute of Applied Sciences and Technology (INSAT), Tunis, Tunisia Degree: Engineering Degree in Chemical & Process Engineering (2022 – Present) Graduation / End-of-Studies Availability: February 2027 (4–6 Months Internship) Key Academic Disciplines & Laboratories: - Advanced Chemical Thermodynamics & Multi-Phase Equilibria - Separation Processes & Distillation Column Internals Design - Chemical Reaction Engineering & Industrial Catalysis - Transport Phenomena (Fluid Mechanics, Heat Transfer, Mass Transfer) - Process Dynamics, Control & Safety Instrumented Systems (SIS) - Chemical Plant Design, Optimization & Engineering Economics ================================================================================ 7. LEADERSHIP, VOLUNTEERISM & CTF ================================================================================ - SecuriNets ENSIT: Founding Committee Member & Media Manager (Apr 2024 – Jan 2025). Co-founded the club, organized DarkNets CTF (Capture The Flag) drawing 200+ attendees and recruiting 50+ members. - IEEE PES × PELS Joint Chapter Student Branch: Media Manager (Sep 2023 – May 2024). Directed media team, published 60+ technical posts, achieved +250% membership growth. ================================================================================ 8. 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