Module 1

Pipeline Design Basis

This course marks the transition from plant piping into onshore pipeline engineering — a closely related but distinct discipline. Where plant piping lives inside the fence under ASME B31.3, the transmission pipeline runs for tens of kilometres across deserts, farmland and townships, buried and fully restrained by the soil around it, and governed instead by ASME B31.8 (gas), ASME B31.4 (liquids) and ISO 13623.

Module 1 sets the design basis: the flow assurance study, the coordinate system, route and corridor selection, spacing, sectionalizing valves and the optimization study that frames every later calculation.

7 lessonsASME B31.8 · B31.4 · ISO 13623by Donny A. Bachtiar

Section 1.0Course Introduction & Objectives

During the conceptual design phase the client typically provides a project overview — the purpose of the pipeline, start and tie-in points, approximate length, expected daily flow rate, and a preliminary diameter. From that the pipeline engineer begins, and the work divides into two streams:

• Flow Assurance Study — steady-state and transient analysis to fix a preferred diameter that carries the maximum flow between the inlet and delivery pressure limits, and to assess surge.
• Pipeline Design — the core engineering: specification, wall thickness, route/corridor drawings, crossing and valve-station details, plot plan, schematics, supports and anchors, hydrotest diagram, ductile-fracture study and (sometimes) the material requisition.

Section 1.1Flow Assurance Basic Theory

Flow assurance is the engineering process of guaranteeing that produced fluids can be transported reliably and economically from the reservoir to the delivery point throughout the entire life of the field. It combines knowledge of fluid behaviour with thermal-hydraulic analysis to develop strategies that keep the flow path clear of anything that would obstruct, restrict or stop production.

The term was coined by Petrobras in the early 1990s, originally covering only the thermal-hydraulic and production-chemistry problems of offshore production. The problems themselves are far older — hydrate blockages were recognised in gas pipelines in the 1930s, and methanol was already in use to suppress them. What changed was the move into deepwater and long tiebacks, where a single blockage can shut in a development for weeks. Today the discipline spans the earliest concept-selection decisions through to abandonment.

For an onshore transmission pipeline, the primary goal is to select an optimal configuration that ensures reliable hydraulic performance and robust operability over the pipeline's life — introducing mitigations, where necessary, against upsets from the fluid's thermo-hydraulic characteristics or its production chemistry.

The two branches of flow assurance

Flow assurance rests on two complementary pillars:

• Fluid hydrodynamics — the physics of how the fluids move through the pipe: multiphase flow regimes, slugging, liquid holdup, pressure drop and erosion. It asks "will it flow?"
• Production chemistry — what the fluids do as pressure and temperature change along the line: hydrates, wax, asphaltenes, scale, emulsions, foaming and corrosion. It asks "will it stay clean while it flows?"

The principal flow assurance threats

For a given fluid, each solid appears within a specific window of pressure and temperature, then deposits on the pipe wall — progressively narrowing the bore until the line plugs.

Hydrates are usually the most feared — they form fastest and can plug a line during cooldown and restart, exactly when the fluid is coldest. Slugging matters most to the pipeline engineer: its intermittent pressure and flow surges impose cyclic loads on the pipeline–riser system that become real cases for stress and support design.

The flow assurance workflow

Although every project differs, the flow assurance process has become standardised into a recognisable sequence, front-loaded into FEED — getting it wrong early is enormously expensive to correct later.

Reading the stages in turn:

• 1 — Fluid characterisation. Validate the reservoir-fluid data and identify which issues apply. Outputs: PVT data, wax properties, the hydrate curve, asphaltene-stability and scale assessment.
• 2 — Steady-state thermal-hydraulics. Establish the concept under steady flow. Outputs: flowline pressure and rate, line size, maximum allowable slug size, insulation requirement.
• 3 — Transient thermal-hydraulics. Test under changing conditions — start-up, shut-down, blowdown, warm-up — with the risk and safe-operating analysis. This is where the real risk lives, because cooldown after a shut-in is when hydrates and wax form.
• 4 — Re-evaluate the preferred concept. Candidate concepts are screened on CAPEX and OPEX; note the feedback loop — the economics feed back into the technical choice.
• 5 — Detailed analyses. Take the fixed concept to detailed design: operating logic, chemical-injection type and rates, storage volumes, host-facility requirements.
• 6 — Risk management plan. Update the FA risk management plan and develop the operating guidelines; produce the final CAPEX / OPEX and tender packages.

Steady-state and transient analysis

Two analysis modes run through the workflow. The study begins with the steady-state model, built from the start point to the end point. Common tools include OLGA (transient and steady-state) with Multiflash or PVTsim for fluid PVT behaviour. The model needs route topography, layout configuration and pipe geometry; fluid composition is defined as a proportion of the production rate, together with all process data — scenarios, inlet pressure, tie-in pressure and MAOP. Simulations are run for a range of diameters; pressure and temperature are evaluated and hydrate (or other) risk assessed. The analysis identifies hydraulic capacity, velocity and erosional velocity, and defines steady-state operating pressures/temperatures as input to the mechanical design. The preferred diameter is selected on hydraulic capacity and flow stability.

Once steady-state is complete, the transient analysis captures time-dependent behaviour:

• Ramp-up — liquid surge and gas-rate increase developed during ramp-up from turndown.
• Ramp-down — the transition period to reach a new steady state after a flow reduction.
• Scraping — liquid surge into the slug catcher generated during pigging.

The transient work also confirms the selected size is fit for purpose for the required maximum flow, inlet pressure and tie-in pressure. As a rule of thumb: steady-state sizes the system, while transient exposes the genuine hazards during start-up, shut-in and restart.

Software used in the oil & gas industry

Flow assurance is almost entirely simulation-driven. A fluid-characterisation (PVT) layer feeds validated fluid models into the hydraulic simulators, which split into steady-state and transient packages.

Section 1.2Coordinate System

The coordinate system for routing must be agreed and defined at the outset:

• Geodetic Datum — an abstract coordinate system referenced to a surface such as sea level, providing known locations from which to begin surveys.
• Reference Ellipsoid — the preferred surface for geodetic computation and point coordinates. The Hayford Ellipsoid (International Ellipsoid 1924, adopted by the IUGG in 1924) is commonly recommended.
• Projection — Universal Transverse Mercator (UTM), a plane-coordinate grid named for the Transverse Mercator projection.

Section 1.3Pipeline Routing

The initial route is developed from the client's planimetric data. Any existing corridor is evaluated to find the best location for the new line, accounting for constructability and feasibility. Key considerations:

• Use the existing corridor and right-of-way as far as possible to minimise construction and civil works.
• Optimise pipeline length and the number of bends.
• Reduce cut-and-fill along the right-of-way.
• Maintain proximity to existing infrastructure.
• Minimise the number of crossings.
• Avoid environmentally and ecologically sensitive areas.

Once these are addressed, the layout is drawn in AutoCAD and overlaid in Google Earth Pro.

Section 1.4Pipeline Spacing

Spacing between a new and an existing pipeline on the same corridor follows common practice and the client standard. Adequate clear distance (OD to OD) allows installation and future repairs with minimum risk to the adjacent line.

• Minimum 9 m clear distance (OD to OD) where the two lines are built at different times.
• Minimum 3 m where both are installed at the same time, on the same project by the same contractor.
• Where a buried line surfaces, the rules for aboveground structures/piping apply.

Spacing also applies between the new pipeline and adjacent facilities — overhead power lines, communication towers, burn pits, wells. Each company sets its own clearance to overhead power lines.

Section 1.5Sectionalizing Block Valves & Emergency Isolation

Block valves isolate the pipeline for maintenance and emergencies. Placement prioritises continuous accessibility, and spacing follows ASME B31.8 (gas) or B31.4 (liquid). For gas transmission, ASME B31.8 gives, for guidance:

• Approximately 32 km — Location Class 1
• Approximately 24 km — Location Class 2
• Approximately 16 km — Location Class 3
• Approximately 8 km — Location Class 4

ASME B31.8 permits valves aboveground, in a vault, or buried; the operating device must remain accessible to authorised personnel, at the operating company's discretion.

Figure 1 — Sectionalizing valve station: mainline isolation with bypass and pigging provision

Emergency Isolation Valves

For some services, EIVs isolate the line during a leak or fire. They are placed between sections of differing class, within the lower class, at boundaries such as Class 1/3, Class 2/3, Class 2/4 and Class 3/4.

Section 1.6Pipeline Optimization Study

Every new pipeline is studied for technical and economic feasibility. Depending on client requirements the study usually includes:

• Pipe geometrical properties
• Pipe material selection
• Routing, construction method and cost analysis (capital, operation, maintenance)
• Area classification
• Operating conditions
• Constructability
• Expected flow rate, flow pattern and velocity limitation
• Corrosion protection requirements
• Hydraulic and flow assurance studies

Section 2.1Design Factor

The Design Factor is a value used to determine nominal wall thickness for a given design pressure (ASME B31.8 / B31.4). Per ASME B31.8-2025, F is selected from the Location Class; Class 1 Division 1 allows up to 0.80 with associated hydrotest requirements.

• Location Class 1 — ≤10 buildings per 1-mile section: deserts, mountains, farmland, sparsely populated areas. Div 1: F > 0.72 up to 0.80, tested to 1.25× MOP. Div 2: F ≤ 0.72, tested to 1.10× MOP.
• Location Class 2 — >10 but <46 buildings: fringe areas, industrial areas, ranches, country estates.
• Location Class 3 — 46 or more buildings (except where Class 4 prevails): suburban, shopping centres, residential/industrial.
• Location Class 4 — multi-storey buildings prevalent, heavy traffic, many underground utilities.

For ASME B31.4 (liquids/slurries) F shall not exceed 0.72; for sea-water, water-disposal and water-injection services 0.72 may be used.

Section 2.2Population Density Index

The term "Population Density Index" has been removed from the codes and replaced by the same terminology used for the design-location class; it is retained here for explanation. From a pipeline perspective it is the number of human-occupancy buildings (and equipment) per 1 km section, translating to Location Class as: Class 1 (≤10), Class 2 (11–30), Class 3 (>30), Class 4 (schools, hospitals, hotels, malls, 4+ storey buildings).

The route is divided into 1 km sections (≈300 m inside live plants at the ends), buildings counted per kilometre, and a table built to identify index, class and Design Factor. Changing from Class 1 (0.72) to Class 2 (0.60) at a highway/railroad crossing extends 500 m either side, perpendicular from the right-of-way edge.

Section 2.3Operating Conditions & Definitions

Pin these down before any calculation:

• Design Pressure — maximum pressure permitted by code for component pressure design.
• MAOP — maximum allowable operating pressure per the Code.
• MOP — highest pressure during a normal operating cycle.
• Normal Operating Pressure — predicted pressure (static head + friction losses + back pressure) under steady-state.
• Pressure Test — fill with liquid, seal and pressurise to validate integrity and detect defects.
• Ambient / Ground Temperature — surroundings / earth temperature at burial depth.
• Max / Min Design Temperature — highest metal temperature in normal operation / lowest anticipated material temperature.
• SMYS — minimum yield strength prescribed in the purchase specification (psi or MPa).
• Design Life — period used in calculations; need not equal system life (a maintained, protected pipeline can serve indefinitely).
• Restrained Pipeline — soil/supports prevent axial displacement or flexure at bends.
• Unrestrained Pipeline — free to displace axially or flex at bends.
• Tie-In Pressure — pressure of the existing line tied into; a basis for sizing and back-pressure checks.

Section 2.4Wall Thickness Calculation

Calculate wall thickness to the governing code. The three common frameworks are below.

ASME B31.8–2025

ISO 13623:2017

ASME B31.4–2025

Once t_n is known, select a commercial wall thickness t_s > t_n from the nearest available value (ASME B36.10).

Section 3.1Stress Properties

For common carbon and low-alloy steels, the coefficient of thermal expansion is ≈ 6.5×10⁻⁶ in/in/°F (1.17×10⁻⁵ cm/cm/°C); ASME B31.8 tabulates expansion (Table 832.2-1) and modulus (Table 832.5-1, e.g. 29.5×10⁶ psi / 203 GPa at 70°F). The relations below are from ASME B31.8.

Section 3.2Axial Stress & Anchor Force

When the fluid temperature in a buried pipe differs from the soil temperature, a straight pipe fully restrained by the soil develops an axial stress:

Where the buried pipe contains a bend it is not assumed fully restrained; expansion around the bend is analysed in a pipe stress program with soil modelled as spring elements. An anchor is installed at each end (restraint by soil friction or longitudinal stress). Where an anchor is needed at a bend, it must distribute load so bearing pressure stays within safe soil limits.

Section 3.3Code Stress Calculations (Von Mises)

The combined biaxial stress in the operating mode is evaluated with the Von Mises equation, following ISO 13623:2017. The summed longitudinal stress is then compared with the allowable.

Hoop stress (σ_hp)

Longitudinal & combined stress

Elastic bending radius

Direction changes are routed by elastic bending where space allows; the resulting stresses must stay within code limits.

Section 4.1Depth of Cover

Depth of cover is the distance from the top of the buried pipe to the surface, protecting the pipe from excessive external loading. The minimum is typically 900 mm above the pipe. At bends, the required depth is confirmed by computer to ensure the pipe will not bow out of the ground. The 900 mm is a reference only — client requirements vary. After burial, the ground surface is restored with suitable fill or graded to match the surroundings.

Figure 2 — Buried pipeline depth of cover: 900 mm top cover, 200 mm bedding, trench width D + 400 mm

Section 4.2Soil Loads

Soil load on a buried pipe is estimated with the prism formula — the earth load equals the weight of the soil prism directly above the pipe.

Below the water table, soil pressure is reduced by buoyancy and increased by the weight of water:

Section 4.3Pipeline Crossings & Trenchless Methods

A buried line must cross other pipelines, cables, fences and — most notably — highways and railways. Concrete slabs, encasements, culverts or bridges may protect it; without such cover (with or without a steel casing) a minimum depth of ≈0.9–1.2 m protects the pipe. ASME B31.8 points to API RP 1102, GRI Report 91/0284 and GPTC Appendix G-15. A crossing beneath a power line must be at 45–135° to the pipeline axis, with minimum horizontal separation from poles/supports.

Trenchless requirements

The technique is selected on feasibility, location, diameter, subsurface condition, geotechnical data and cost–benefit, performed by an experienced contractor. Girth-weld coating and abrasion-resistant overlay (ARO) must be identified, and elastic bending stress, bend angle, hoop stress and external-pressure stresses during installation calculated. Available techniques:

• HDD — Horizontal Directional Drilling
• Micro-tunnelling
• Direct Pipe drilling
• Pipe jacking
• Pipe ramming
• Horizontal auger boring / drilling
• Pipe bursting

External coating applies to pipe and casing including field welds; cathodic protection applies to cased and uncased sections.

Section 4.4Surface Loads

Where the line crosses highways and railways it carries heavy traffic load. The pressure transmitted to the pipe is:

Under combined soil and external load the pipe ovalizes, producing through-wall bending stress:

Section 4.5Scraper Trap

A scraper is any device for internal cleaning, gauging and inspection; a trap launches or receives it. Traps sit at the start (launcher) and end (receiver), and may be permanent or portable. Provision is planned in advance with all tie-in valves to avoid shutdown. Where bi-directional flow is possible — or the hydrotest water source can be at either end — the trap is designed for bi-directional scraping.

There are two full-bore trap isolation valves matching the line size, and a barred tee in the mainline (a standard tee with bar plates inside the branch) to stop the pig passing into the branch. The trap carries a tight-sealing quick-opening end closure, davit-supported, sometimes with a mechanical opening aid.

Figure 3 — Scraper launcher / receiver: schematic per ASME B31.8 & ASME B31.3

Figure 4 — Scraper launcher / receiver: schematic per ISO 13623 & ASME B31.3, showing the code break for pig traps

Section 5.1Ductile Fracture Propagation

A severe gas-pipeline accident is wall failure and fracture initiation evolving into a long running fracture if toughness is inadequate. It is controlled by specifying a minimum line-pipe toughness (Charpy V-notch energy) or mechanical crack arrestors. Risk is lowered by increasing wall thickness or toughness, decreasing diameter, or increasing yield strength / grade.

The most accepted approach is the Battelle Two-Curve Method (BTCM), developed in the 1970s and embedded in ISO, API and DNV-GL standards. BTCM treats fracture resistance and driving force separately — the driving force from gas decompression (composition, temperature, pressure) and the resistance from material and geometry. ASME B31.8 requires either adequate toughness to arrest a ductile fracture or crack arrestors; pipe is tested per Annex G of API 5L. Fracture control is required when:

• Hoop stress over 40% through 80% of SMYS in sizes NPS 16 (DN 400) or larger;
• Hoop stress over 72% through 80% of SMYS in sizes smaller than NPS 16 (DN 400);
• Minimum design temperature below −20°F (−29°C), per section 812.

The all-heat average Charpy energy must meet or exceed:

Section 5.2Coating & Corrosion Protection

A corrosion-management programme is developed for every new pipeline. For underground systems there are two protection types:

• Internal corrosion protection — depends on the fluid carried.
• External corrosion protection — depends on the burial environment; buried line pipe is commonly coated with fusion-bonded epoxy (FBE), aboveground sections painted to standard.

FBE is a common internal and external option, including girth-weld coating for sour and other services. Where the line surfaces, the transition is protected with buried-service coating plus a wrap extended 1 m above ground for sharp angles (46–90°); shallower angles need a longer extension per company standard. In addition to FBE, a cathodic protection (CP) system protects the line, with electrical isolating kits at aboveground piping. Some operators also require a leak detection system (LDS) after a risk assessment.

Section 5.3Upheaval Buckling Analysis

Upheaval buckling occurs when out-of-straightness combines with high axial compressive force from extreme operating conditions, buckling the line upward. It is prevented by burying deep enough that the soil cover resists uplift. The relations below outline the analysis (representative, not complete); for full treatment see Dr K. Peters’ paper, George Antaki’s Piping and Pipeline Engineering, and DNV-RP-F110.

A buoyancy assessment is also required: total pipeline weight must exceed the displaced soil weight (commonly with a 10% margin), checked for installed phases (empty; corroded + dry backfill; fully submerged) and the construction phase (empty, no backfill).