Pressure Vessels
What Is a Pressure Vessel
A pressure vessel is a closed container that holds fluids (gases, vapors, or liquids) at a pressure significantly higher or lower than atmospheric pressure. In the oil and gas industry, pressure vessels are the workhorses of process plants. They separate gas from liquid phases, contain shell-side fluids in heat exchangers, house catalysts for chemical reactions, store pressurized liquefied gases, and provide surge or buffer capacity as suction drums and accumulators.
The fundamental engineering challenge is managing the hoop stress that internal pressure generates in the vessel walls. Because a failure can release enormous stored energy (equivalent to an explosion) pressure vessels are among the most heavily regulated pieces of industrial equipment worldwide. In the United States and much of the international oil and gas sector, ASME Boiler and Pressure Vessel Code (BPVC) Section VIII is the governing design standard, while fabrication shops must hold an ASME U-stamp certificate of authorization. Inspection during service falls under API 510 and API 572.
Pressure vessels range in size from small instrument air receivers of a few liters to massive refinery coke drums exceeding 12 meters in diameter. Regardless of size, the design philosophy remains the same: contain the design pressure and temperature with an appropriate safety margin, accommodate all load combinations (pressure, dead weight, wind, seismic, nozzle loads), and provide for safe inspection and maintenance throughout the vessel’s service life.
Key Takeaway: Pressure vessels are code-governed containers that hold fluids above (or below) atmospheric pressure. Their design, fabrication, inspection, and repair are regulated by ASME Section VIII and API standards to prevent catastrophic failures in oil & gas facilities.
Horizontal Pressure Vessel: Cross-Section Diagram
Types of Pressure Vessels
Pressure vessels in oil and gas service can be broadly categorized by orientation (horizontal or vertical), geometry (cylindrical or spherical), and function (separation, storage, reaction, heat exchange). The choice of vessel type depends on process requirements, plot space, liquid holdup volume, and the nature of the fluids being handled.
Horizontal Vessels
Horizontal pressure vessels are the most commonly encountered configuration in oil and gas process plants. Their low center of gravity provides inherent stability, and the elongated horizontal profile offers a large liquid surface area, which makes them especially effective for gas-liquid separation and surge/buffer duties.
| Application | Function | Notes |
|---|---|---|
| Process drums (reflux, suction, flash) | Provide intermediate liquid holdup between process units | A reflux drum receives overhead condensate from a distillation column and allows vapor to disengage before liquid returns as reflux |
| Knock-out drums (KO drums) | Remove entrained liquid droplets from gas streams upstream of compressors or flare headers | Prevent liquid carryover that could damage rotating equipment or cause unstable flare combustion |
| Suction scrubbers | Protect compressor inlets from liquid ingestion | Often include mesh pad or vane-type mist eliminators; target liquid carryover below 0.1 gal/MMSCF |
| Test separators | Measure individual well flow rates in upstream production | Three-phase separation (gas, oil, water) with independent metering on each phase |
| Pig receivers/launchers | Insert and receive pipeline pigs for cleaning or inspection | Equipped with quick-opening closures |
Horizontal vessels sit on saddle supports (also called Zick saddles), which distribute the vessel weight and contents over the foundation. The saddle design must account for thermal expansion; typically one saddle is fixed and the other slides.
Vertical Vessels
Vertical pressure vessels are preferred when plot space is limited, when the process requires gravity-driven liquid drainage, or when the vessel must accommodate tall internals such as trays, packing, or demister pads. They sit on skirts (cylindrical shell extensions welded to the bottom head) or leg supports for smaller vessels.
| Application | Function | Notes |
|---|---|---|
| Vertical separators | Two-phase or three-phase separation where footprint is constrained (e.g., offshore platforms) | Better gas-liquid disengagement when gas flow is low relative to liquid rate |
| Scrubbers and filters | Remove particulates or mist from gas streams | Contain internal filter elements, mesh pads, or vane packs |
| Surge drums | Accumulate fluid in compressor systems or hydraulic circuits | Vertical orientation suits limited plot area |
| Columns and towers | Distillation, absorption, stripping, extraction (often 30-60 m tall) | Contain trays (sieve, valve, bubble-cap) or structured/random packing. See Distillation Columns & Reactors |
Vertical vessels experience significant wind and seismic loads due to their height-to-diameter ratio. The skirt-to-head junction and anchor bolt design are critical structural elements that must be analyzed for overturning moment and base shear.
Spherical Vessels (Horton Spheres)
Spherical vessels offer the most efficient geometry for containing internal pressure because the stress distributes uniformly across the shell in all directions (equal meridional and hoop stresses). This means a sphere requires roughly half the wall thickness of an equivalent cylindrical vessel for the same pressure and diameter, yielding significant material savings for large-diameter, high-pressure applications.
Spherical vessels (commonly known as Horton spheres after the Chicago Bridge & Iron Company engineer who popularized the design) serve primarily as storage for LPG (propane, butane) at 150-250 psig, NGL (natural gas liquids) at similar pressure ranges, ammonia and nitrogen in petrochemical complexes, and hydrogen where very high pressures demand maximum structural efficiency.
Typical spherical vessel diameters range from 10 to 25 meters, with wall thicknesses of 25 to 75 mm depending on the design pressure and material grade. They sit on a ring of equatorial columns (typically 8 to 20 legs) connected by bracing members.
The main disadvantage of spherical vessels is their high fabrication cost; the curved shell plates (called gores or petals) require complex forming and extensive welding. For this reason, spherical vessels are only economical for very large storage volumes where the material savings outweigh the additional fabrication expense.
Reactors
Reactor vessels operate under some of the most severe conditions in the oil and gas industry, combining high pressures (often 1,500-3,000 psig) with high temperatures (350-500 C) and corrosive or hydrogen-rich environments. They contain catalysts and facilitate chemical reactions such as hydrocracking, hydrotreating, catalytic reforming, and fluid catalytic cracking (FCC).
| Feature | Details |
|---|---|
| Wall construction | 150-300 mm of low-alloy steel (SA-387 Gr.11 or Gr.22) with stainless steel weld overlay or cladding on the internal surface |
| Catalyst support | Internal support grids and distribution trays hold and distribute catalyst beds |
| Temperature monitoring | Thermowell nozzles throughout the catalyst beds |
| Quench systems | Cold hydrogen injection nozzles between catalyst beds control temperature rise |
Due to the hydrogen-rich environment, reactor vessels are subject to hydrogen attack (Nelson curves) and temper embrittlement, requiring careful material selection, PWHT control, and in-service monitoring. For more detail on column and reactor design, refer to Distillation Columns & Reactors.
Vessel Head Types Comparison
ASME Section VIII Overview
The ASME Boiler and Pressure Vessel Code (BPVC) Section VIII is the primary design code for pressure vessels in the oil and gas industry worldwide. It is published by the American Society of Mechanical Engineers and is updated on a two-year cycle. Section VIII is organized into three divisions, each suited to different pressure ranges and design philosophies.
Division 1: Design by Rules
Division 1 is the most widely used division for conventional pressure vessels in oil and gas applications. It provides prescriptive rules (formulas and tables) for determining minimum wall thickness, nozzle reinforcement requirements, flange ratings, and other design parameters.
The fundamental formula for minimum required wall thickness of a cylindrical shell under internal pressure is:
t = PR / (SE - 0.6P)
Where:
- t = minimum required thickness (inches or mm)
- P = internal design pressure (psi or MPa)
- R = inside radius of the shell (inches or mm)
- S = maximum allowable stress value of the material at design temperature (from ASME Section II, Part D)
- E = joint efficiency factor (depends on weld joint category and degree of radiographic examination: 1.0 for full RT, 0.85 for spot RT, 0.70 for no RT)
For a 2:1 ellipsoidal head, the required thickness formula is:
t = PD / (2SE - 0.2P)
Where D is the inside diameter of the head skirt (equal to the shell inside diameter).
Division 1 covers vessels with design pressures up to approximately 3,000 psi (20 MPa), though there is no explicit upper pressure limit. It is the default choice for most process drums, separators, heat exchanger shells, and storage vessels.
Division 2: Design by Analysis
Division 2 (also known as the Alternative Rules) permits a more rigorous engineering approach using stress analysis techniques, including finite element analysis (FEA). In exchange for this additional analytical effort, Division 2 allows higher allowable stress values (typically 10-15% higher than Division 1), resulting in thinner walls and lighter vessels.
Division 2 is advantageous for heavy-wall vessels where material savings from higher allowable stresses justify the additional engineering cost, for complex geometries that Division 1’s prescriptive rules cannot adequately address, and for vessels subject to cyclic loading where a detailed fatigue analysis is required.
The design-by-analysis approach in Division 2 categorizes stresses into primary (load-controlled), secondary (strain-controlled), and peak (localized) stresses, each with different allowable limits. This methodology follows the Hopper diagram for stress classification.
Division 3: High-Pressure Vessels
Division 3 covers vessels operating at pressures above 10,000 psi (69 MPa). These are specialized vessels used in autoclaves for composite curing, isostatic pressing equipment, ultra-high-pressure research vessels, and some gas storage and waterjet cutting systems.
Division 3 vessels often employ multilayer, wire-wound, or shrink-fit construction techniques to achieve the required wall thickness while maintaining fabricability. This division is rarely encountered in conventional oil and gas processing but may apply to certain high-pressure well testing or gas injection equipment.
Joint Efficiency and Allowable Stress
The joint efficiency factor (E) is a critical parameter in Division 1 design. It accounts for the fact that welded joints may contain undetected flaws that reduce the effective strength of the joint.
| Joint Category | Full Radiography (RT) | Spot RT | No RT |
|---|---|---|---|
| Type 1 (Double-welded butt) | 1.00 | 0.85 | 0.70 |
| Type 2 (Single-welded butt with backing) | 0.90 | 0.80 | 0.65 |
| Type 3 (Single-welded butt, no backing) | - | - | 0.60 |
| Type 4 (Double full-fillet lap) | - | - | 0.55 |
Choosing a higher joint efficiency (through more extensive NDE) directly reduces the required wall thickness and therefore the vessel weight and cost. For this reason, most oil and gas pressure vessels are specified with full radiography (E = 1.0) on all main seam welds.
Nozzle Reinforcement Detail
Nozzle Reinforcement (UG-37)
When a nozzle penetrates the shell of a pressure vessel, it creates an opening that interrupts the hoop stress path. The shell around the opening must carry additional stress, and without reinforcement, a localized failure can occur. ASME Section VIII, Division 1, paragraph UG-37 addresses this through the area-replacement method.
The basic principle is straightforward: the cross-sectional area of metal removed by the opening (measured in the plane containing the axis of the nozzle and the axis of the vessel) must be replaced by an equivalent area of metal in the immediate vicinity of the opening. The replacement metal can come from four sources: excess thickness in the shell wall above what pressure requires, excess thickness in the nozzle wall, weld metal deposited at the nozzle-to-shell junction, or a reinforcement pad (repad) — an annular plate welded around the nozzle on the outside of the shell.
Reinforcement pads are the most common method for nozzles larger than approximately 2 inches (50 mm) in diameter. The pad is typically made from the same material as the shell and is attached with fillet welds at the outer edge and at the nozzle neck. A small tell-tale hole (typically 1/4 inch or 6 mm) is drilled through the pad to serve as a leak indicator and to vent any trapped gases during PWHT or hydrostatic testing.
Standards and Specifications
Key codes and standards applicable to pressure vessels in oil and gas service:
| Standard | Title / Description |
|---|---|
| ASME BPVC Section VIII, Div 1 | Pressure Vessels. Rules for Construction (design by rules). The primary design code for most oil & gas pressure vessels. |
| ASME BPVC Section VIII, Div 2 | Pressure Vessels. Alternative Rules (design by analysis). Allows higher allowable stresses with detailed stress analysis. |
| ASME BPVC Section VIII, Div 3 | Pressure Vessels. Alternative Rules for Construction of High Pressure Vessels (above 10,000 psi). |
| ASME BPVC Section II, Part D | Materials. Properties (allowable stress tables, physical properties, external pressure charts). |
| ASME BPVC Section V | Nondestructive Examination. Procedures for RT, UT, MT, PT, VT, and other NDE methods. |
| ASME BPVC Section IX | Welding, Brazing, and Fusing Qualifications. WPS, PQR, and welder performance qualifications. |
| API 510 | Pressure Vessel Inspection Code. In-service inspection, repair, alteration, and re-rating of pressure vessels. |
| API 572 | Inspection Practices for Pressure Vessels. Supplementary guidance on inspection techniques and deterioration mechanisms. |
| API 579-1 / ASME FFS-1 | Fitness-for-Service. Engineering assessment procedures for equipment with flaws, damage, or operating outside original design conditions. |
| API 580 / 581 | Risk-Based Inspection (RBI). Methodology for prioritizing inspection resources based on risk of failure. |
| NACE MR0175 / ISO 15156 | Materials for use in H2S-containing environments in oil and gas production (sour service requirements). |
| ASME PCC-2 | Repair of Pressure Equipment and Piping. Methods for permanent and temporary repairs. |
Head Types Comparison
The choice of head type significantly affects the vessel’s pressure-bearing efficiency, wall thickness, weight, and cost.
| Head Type | Max Practical Pressure | Relative Cost | Thickness vs. Shell | Stress Distribution | Typical Application |
|---|---|---|---|---|---|
| Hemispherical | Unlimited (highest efficiency) | Highest (complex forming) | 50% of shell thickness | Uniform. Equal hoop and meridional stress | High-pressure reactors, sphere segments, thick-wall vessels |
| 2:1 Ellipsoidal | Up to ~3,000 psi | Moderate | ~100% of shell thickness | Good. Smooth stress transition at knuckle | Standard choice for most oil & gas process vessels |
| Torispherical (ASME F&D) | Up to ~150 psi | Lowest formed head | ~150-170% of shell thickness | Fair. Stress concentration at crown-to-knuckle transition | Low-pressure tanks, atmospheric vessels, utility service |
| Flat (Blind) | Very low (< 50 psi) | Lowest | Very thick (bending-dominated) | Poor. High bending stress at edge | Small openings, handhole covers, low-pressure chambers |
The 2:1 ellipsoidal head is by far the most common head type in oil and gas pressure vessels because it represents the best compromise between structural efficiency, ease of fabrication, and cost. The designation “2:1” refers to the ratio of the major axis (diameter) to the minor axis (depth), where the head depth equals one-quarter of the inside diameter (D/4).
Torispherical heads (also called flanged and dished, or F&D heads) consist of a spherical crown radius (typically equal to the outside diameter) connected to a toroidal knuckle radius (typically 6% of the outside diameter). They are shallower and cheaper than ellipsoidal heads but have a stress concentration at the crown-to-knuckle junction that limits their use to lower pressures.
Materials Selection
Material selection for pressure vessels is governed by the service conditions (pressure, temperature, corrosive environment) and the applicable code requirements. ASME Section VIII references material specifications from ASME Section II, which in turn adopts ASTM specifications with the “SA-” prefix (e.g., ASTM A516 becomes SA-516).
Carbon Steel
SA-516 Grade 70 is the single most widely used pressure vessel steel in the oil and gas industry. It is a carbon-manganese-silicon steel with excellent weldability, good toughness at moderate low temperatures (down to -29 C with normalization and impact testing), and a specified minimum tensile strength of 70 ksi (485 MPa).
Other common carbon steel specifications:
| Specification | Application |
|---|---|
| SA-516 Gr. 60 / 65 | Lower strength grades for thinner sections or improved formability |
| SA-285 Gr. C | Light-duty, low-to-moderate pressure service (limited to 1 inch maximum thickness) |
| SA-106 Gr. B | Seamless pipe for nozzle necks and small-diameter connections |
| SA-105 | Carbon steel forgings for flanges, fittings, and nozzle reinforcement |
Low-Alloy Steel
For elevated-temperature service (above approximately 400 C) and hydrogen service, chrome-moly low-alloy steels provide superior creep strength and hydrogen attack resistance.
| Specification | Composition | Application |
|---|---|---|
| SA-387 Gr. 11 Cl. 2 | 1.25Cr-0.5Mo | Standard material for hydroprocessing reactor shells up to about 470 C |
| SA-387 Gr. 22 Cl. 2 | 2.25Cr-1Mo | Higher chrome content for improved hydrogen resistance; hydrotreater and hydrocracker reactors |
| SA-387 Gr. 91 | 9Cr-1Mo-V | Advanced creep-resistant steel for high-temperature service above 550 C; power generation and some refinery heater tubes |
| SA-336 F11 / F22 | Forging equivalents of plate grades above | Thick-wall components and heads |
Stainless Steel and High-Alloy Materials
Stainless steels and nickel alloys are selected for corrosion resistance in aggressive environments.
| Specification | Grade/Type | Application |
|---|---|---|
| SA-240 Type 304/304L | Austenitic stainless | General corrosion resistance; chemical storage, cryogenic vessels, cladding material |
| SA-240 Type 316/316L | Mo-bearing austenitic | Improved pitting and crevice corrosion resistance; seawater-cooled systems, chloride environments |
| SA-240 Type 321/347 | Stabilized austenitic | High-temperature service where sensitization is a concern |
| SA-240 Type 410S | Ferritic/martensitic | High-temperature sulfur-bearing environments (tray material in crude unit columns) |
| SA-264 | Cr-Ni clad plate | Carbon steel base with stainless steel cladding applied by rolling or explosion bonding |
Clad and Lined Vessels
For many refinery and petrochemical applications, the most economical approach is a clad vessel — a carbon or low-alloy steel shell with a thin (typically 3-6 mm) corrosion-resistant alloy (CRA) layer on the inside surface. This combines the structural strength of the base metal with the corrosion resistance of the alloy lining, at a fraction of the cost of a solid alloy vessel.
Common cladding combinations:
| Base Metal | Cladding | Typical Service |
|---|---|---|
| SA-516 Gr. 70 | Type 316L | Crude unit columns, amine contactors |
| SA-387 Gr. 22 | Type 347 | Hydroprocessing reactors (weld overlay more common than roll-bonded clad for thick-wall reactors) |
| Carbon steel | Alloy 625 | Severe sour gas service, high-chloride environments |
Material Selection for Sour Service (H2S)
Vessels containing hydrogen sulfide (H2S) above the thresholds defined in NACE MR0175 / ISO 15156 must be fabricated from materials resistant to sulfide stress cracking (SSC), hydrogen-induced cracking (HIC), and stress-oriented hydrogen-induced cracking (SOHIC). Key requirements include a maximum hardness of 22 HRC (248 HBW) in base metal, weld metal, and heat-affected zones; carbon steel must be in the normalized, normalized and tempered, or quenched and tempered condition; mandatory PWHT for carbon and low-alloy steel weldments; HIC testing per NACE TM0284 and SSC testing per NACE TM0177 for plate materials in wet sour service; and restrictions on certain alloying elements such as carbon content and microalloying.
Design Considerations
Internal and External Pressure
The majority of pressure vessels handle internal pressure, where the hoop stress in the cylindrical shell is the controlling load. However, some vessels must also withstand external pressure (vacuum conditions), which introduces the risk of buckling — a sudden, catastrophic collapse of the shell.
External pressure design per ASME VIII UG-28 involves iterating through external pressure charts (in Section II, Part D) to determine the allowable external working pressure, which depends on the vessel geometry (L/D and D/t ratios) and the material’s modulus of elasticity at the design temperature. Stiffening rings may be required to reduce the unsupported length and increase the buckling resistance.
Wind and Seismic Loads
Tall vertical vessels (columns, towers) are subject to significant lateral forces from wind and seismic events. These loads create overturning moments at the base of the vessel that must be resisted by the skirt, anchor bolts, and foundation.
Wind loading follows ASCE 7 or local building codes, accounting for the vessel’s height, diameter, insulation thickness, platforms, and ladders. Seismic loading per ASCE 7 or IBC considers site-specific spectral acceleration, importance factor, and response modification factor. Slender columns with a height-to-diameter ratio greater than approximately 15:1 may be susceptible to vortex-induced vibration (VIV), requiring helical strakes or tuned mass dampers.
Cyclic Service
Vessels subjected to cyclic loading (repeated pressure/temperature fluctuations, startup/shutdown cycles) must be evaluated for fatigue. ASME VIII Division 1 provides screening criteria in paragraph UG-22 and Appendix 5 to determine whether a detailed fatigue analysis (per Division 2 procedures) is required.
Common sources of cyclic loading in oil and gas vessels include pressure cycling during batch operations or intermittent compressor operation, thermal cycling from startup/shutdown or temperature swings, and mechanical vibration from reciprocating equipment or fluid-induced pulsation.
Corrosion Allowance
A corrosion allowance (CA) is added to the calculated minimum wall thickness to account for material loss over the vessel’s intended service life. Typical values in oil and gas:
| Corrosion Allowance | Service Conditions |
|---|---|
| 1.5 mm (1/16 in.) | Clean, non-corrosive services — dehydrated gas, steam condensate |
| 3.0 mm (1/8 in.) | Standard process service — most hydrocarbon vessels |
| 6.0 mm (1/4 in.) | Corrosive services — sour gas, amine, crude oil with high acid number |
The corrosion allowance applies to the pressure side of the calculation (added to the required thickness). It does not contribute to the structural strength of the vessel.
Post-Weld Heat Treatment (PWHT)
PWHT is a controlled heating and cooling cycle performed after welding to relieve residual stresses, restore toughness in the heat-affected zone, and reduce hardness for sour service requirements. ASME VIII mandates PWHT based on material type and thickness (carbon steel over approximately 19 mm per UCS-56), service conditions (sour H2S, caustic, or amine service per NACE MR0175), and impact test exemption needs (PWHT can qualify materials for lower minimum design metal temperatures).
Typical PWHT parameters for carbon steel vessels:
| Parameter | Value |
|---|---|
| Holding temperature | 595-650 C (1,100-1,200 F) |
| Holding time | 1 hour per 25 mm (1 in.) of thickness, minimum 1 hour |
| Heating rate | Maximum 220 C/hr (for thickness over 50 mm) |
| Cooling rate | Maximum 280 C/hr in the furnace; free-air cooling below 400 C |
Nozzle Loads
Nozzles on pressure vessels carry external loads from the connected piping (forces and moments in three orthogonal directions). These loads must be checked against allowable values to prevent excessive local stresses at the nozzle-to-shell junction.
The most widely used evaluation methods:
| Method | Application |
|---|---|
| WRC Bulletin 107 / WRC 297 | Analytical calculation of local stresses from external loads on cylindrical and spherical shells |
| PD 5500 Annex G | British standard approach to nozzle load assessment |
| FEA (Finite Element Analysis) | Complex geometries or cases where WRC methods yield marginal results |
Fabrication and Inspection
Welding Processes
Pressure vessel fabrication involves extensive welding, and weld quality directly determines the integrity and service life of the vessel.
| Process | Abbreviation | Primary Use | Characteristics |
|---|---|---|---|
| Submerged Arc Welding | SAW | Longitudinal and circumferential seam welds on shell and heads | High deposition rates, deep penetration, consistent quality; automatic or semi-automatic |
| Shielded Metal Arc Welding | SMAW | Nozzle-to-shell welds, root passes, attachment welds, field repairs | Versatile but lower deposition rate than SAW |
| Gas Tungsten Arc Welding | GTAW (TIG) | Root passes on critical welds (stainless, alloy, clad vessels); weld overlay | Produces smooth, defect-free corrosion-resistant surfaces |
| Flux-Cored Arc Welding | FCAW | Fillet welds and attachment welds | Alternative to SMAW where higher deposition rates are needed |
| Electroslag Welding | ESW | Thick-wall circumferential seams in reactor vessels | Specialized high-deposition process |
All welding must follow qualified Welding Procedure Specifications (WPS) backed by Procedure Qualification Records (PQR) per ASME Section IX. Welders and welding operators must pass performance tests for each welding process, position, and material group they will use.
Nondestructive Examination (NDE)
NDE is the cornerstone of pressure vessel quality assurance. The extent and type of NDE required depends on the joint category, joint efficiency, material, thickness, service conditions, and any supplemental client specifications.
| NDE Method | Abbreviation | What It Detects | Typical Application |
|---|---|---|---|
| Radiographic Testing | RT | Volumetric defects (porosity, slag, incomplete fusion, cracks) | Main seam welds. Longitudinal and circumferential butt joints |
| Ultrasonic Testing | UT | Volumetric defects, laminations, wall thickness | Thick-wall seams (alternative to RT), plate scanning for laminations, in-service thickness monitoring |
| Magnetic Particle Testing | MT | Surface and near-surface cracks | Nozzle welds, attachment welds, skirt-to-shell welds, post-PWHT inspection |
| Liquid Penetrant Testing | PT | Surface-breaking cracks and porosity | Non-ferromagnetic materials (stainless steel, alloy welds), root-pass inspection |
| Visual Testing | VT | Surface defects, weld profile, fit-up, alignment | All welds. The most fundamental and widely used NDE method |
| Phased Array UT (PAUT) | PAUT | Same as UT with improved detection and sizing | Increasingly used as alternative to RT; provides real-time imaging |
Hydrostatic Testing
Before a new pressure vessel can receive the ASME U-stamp, it must pass a hydrostatic test per UG-99. The test pressure is:
P_test = 1.3 x MAWP x (S_test / S_design)
Where:
- MAWP = Maximum Allowable Working Pressure (the stamped pressure)
- S_test = allowable stress at test temperature
- S_design = allowable stress at design temperature
For most vessels tested at ambient temperature with design temperatures below 300 C, the stress ratio is close to 1.0, giving a test pressure of approximately 1.3 times MAWP.
The vessel is filled with water (or another suitable liquid), pressurized to the test pressure, held for a minimum of 30 minutes (for Division 1), and then inspected at MAWP for leaks. All bolted connections, nozzle welds, and seam welds are visually examined during the hold period.
Hydrostatic testing serves multiple purposes: it demonstrates the structural integrity of the vessel and all welded joints, reveals any leaks at flange connections or weld defects, introduces a beneficial compressive residual stress at stress concentrations (auto-frettage effect), and satisfies ASME U-stamp certification requirements.
ASME U-Stamp and the Authorized Inspector
Pressure vessels built to ASME Section VIII must be manufactured by shops holding a valid ASME Certificate of Authorization (U stamp). The fabrication process is overseen by an Authorized Inspector (AI) employed by an ASME-accredited Authorized Inspection Agency (AIA), such as Hartford Steam Boiler, Bureau Veritas, TUV, or Lloyd’s Register.
The AI reviews the design to verify that calculations and drawings conform to the Code, confirms that all materials have proper MTRs (Mill Test Reports) traceable to the ASME specification, witnesses fit-up, welding, NDE, and heat treatment at key hold points, is present during the final hydrostatic test, and authorizes the application of the ASME U-stamp by signing the Manufacturer’s Data Report (Form U-1).
The ASME U-stamp is not a quality stamp indicating that the vessel is of high quality; it is a compliance stamp certifying that the vessel was designed, fabricated, inspected, and tested in accordance with the requirements of ASME Section VIII.
Applications in Oil & Gas
Pressure vessels are found throughout the oil and gas value chain, from wellhead equipment in upstream production to final product storage in downstream refining.
Upstream (Exploration & Production)
| Equipment | Function |
|---|---|
| Production separators | Two-phase and three-phase separation of the wellstream into gas, oil, and water — the first process vessels crude encounters after the wellhead |
| Test separators | Dedicated vessels for metering individual well production rates |
| Heater treaters | Heated vessels that break oil-water emulsions, combining heat and residence time to separate free water and BS&W |
| Gas dehydration contactors | Vertical vessels with structured packing or trays where wet gas contacts triethylene glycol (TEG) to remove water vapor |
| FWKO (Free Water Knock-Out) drums | Horizontal vessels that remove bulk free water from the crude oil stream before further processing |
| HP/LP production traps | High-pressure and low-pressure separators in multi-stage separation trains |
Midstream (Transportation & Processing)
| Equipment | Function |
|---|---|
| Compressor suction scrubbers | Vertical vessels that protect reciprocating and centrifugal compressors from liquid slugs |
| NGL fractionation towers | Tall vertical pressure vessels operating at 200-400 psig, separating natural gas liquids into ethane, propane, butane, and natural gasoline |
| Amine contactors and regenerators | Gas sweetening vessels that remove H2S and CO2 using amine solutions (MEA, DEA, MDEA) |
| LPG storage spheres | Large spherical pressure vessels for storing liquefied propane and butane at gas plants and export terminals |
| Slug catchers | Very large horizontal vessels or pipe arrays at pipeline receiving terminals that absorb liquid slugs from long-distance gas pipelines |
Downstream (Refining & Petrochemicals)
| Equipment | Function |
|---|---|
| Crude unit columns | Atmospheric and vacuum distillation columns — among the largest pressure vessels in a refinery |
| Hydroprocessing reactors | Thick-wall, high-pressure vessels for hydrotreating, hydrocracking, and catalytic reforming |
| Coke drums | Large vertical vessels (up to 12 m diameter) that undergo severe thermal cycling in delayed coking units |
| Heat exchanger shells | Pressure-containing shells of shell-and-tube exchangers, built per ASME VIII (while the exchanger as a whole follows TEMA) |
| Overhead accumulators / reflux drums | Horizontal vessels that collect condensed overhead product from distillation columns |
| Flare KO drums | Vessels in the flare system that capture liquid carryover before gas reaches the flare tip |
Key Takeaway: Pressure vessels serve critical roles across all three sectors of the oil and gas industry. From wellhead separators in upstream production to massive refinery reactors and LPG storage spheres, these code-governed containers must be designed, fabricated, and maintained to exacting standards to ensure safe, reliable operation throughout their service life.
Related Articles
- Heat Exchangers. Shell-and-tube, plate, air-cooled exchangers for oil & gas
- Oil & Gas Separators. Two-phase and three-phase separator design and internals
- Storage Tanks. Atmospheric and low-pressure storage tank types (API 650, API 620)
- Distillation Columns & Reactors. Trayed and packed columns, reactor vessel design
- Upstream, Midstream & Downstream Equipment Overview. Complete overview of equipment across the oil & gas value chain
Related quick answers: What Is a Storage Tank? | What Is a Sample Point?
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