Industrial Pump Selection Engineering Guide

What Is Pump Selection?

Pump selection is a system-engineering decision: the selected pump must satisfy the hydraulic duty, liquid properties, suction conditions, mechanical limits, materials, driver, control philosophy, reliability target and project standard.

An ideal pump-selection program requires all six areas emphasized in the original Petropedam training presentation:

The Engineering Selection Process

Data Required for Pump Selection

A complete process datasheet is the foundation. Below is a comprehensive checklist of essential parameters.

Fluid Properties — The Foundation of Pump Selection

Liquid properties can change pump type, curve correction, NPSH, materials, sealing, power and minimum-flow requirements. Use properties at the actual operating temperature — not only at ambient conditions.

Critical Fluid Characteristics

• pH / chemical composition: evaluate at concentration and temperature, including trace halides, sulfides and other aggressive species.
• Suspended solids: define concentration, PSD, hardness, shape and settling tendency — not only a percentage.
• Free / entrained gas: can reduce developed head, efficiency and stability and may cause gas locking. Distinguish it from gas that remains dissolved and from vapor bubbles caused by cavitation.
• Allowable leakage / toxicity: may control the sealing concept and can justify dual seals, containment or sealless technology.
• Product sensitivity: contamination, shear, crystallization, polymerization or temperature limits may govern technology selection.

System Characteristics & Operating Point

The pump does not choose the flow independently. The operating flow occurs where the pump curve intersects the system curve for the active piping, vessel pressures and control configuration.

The vessels and piping largely define the steady system requirement independently of the selected pump. For reciprocating or some rotary pumps, pulsation and acceleration can also change the instantaneous suction condition; evaluate inlet adequacy with the actual pump and duty.

Trace the liquid from vessel 1 to vessel 2

The source vessel sets pressure P₁ and liquid level z₁. The pump draws liquid through the suction pipe (point 2), adds head between its suction and discharge connections (points 2 and 3), and sends the flow through discharge piping to the receiving vessel at P₂ and z₂ (point 4). Pipe and equipment losses increase with flow; the energy balance therefore changes as Q changes.

Read the source sketch's hydraulic gradient: energy falls along the suction and discharge pipework because of losses and rises across the pump by the head it adds. The suction pressure must also remain sufficiently above the liquid's vapor pressure; NPSHA is checked separately from the plotted total system head.

From the physical route to the operating point

For this illustrative turbulent-flow case, required head is approximately H_system(Q) = H_{static+pressure} + h_loss(Q), with h_loss often approximated as KQ² over a limited operating range. The intersection with the vendor's pump H–Q curve gives the installed operating point; changing vessel levels, pressures or a valve changes the system curve.

Source: Petropedam engineering training material; Hydraulic Institute: pump/system operating point and NPSHA terminology.

Reference Datums & Pressure Basis

• Use a consistent elevation datum for static head calculations.
• Pressure differences used for TDH may be based on gauge or absolute pressure provided both are consistent; NPSH calculations require absolute pressure.
• For vertical pumps, define the applicable first-stage impeller datum for NPSH.
• Calculate the system curve for each meaningful valve/equipment configuration, not only one “normal” condition.

Pump Classification — Choose the Technology from the Service

The original presentation separates kinetic/rotodynamic and displacement pumps. That framework remains useful, but no single variable such as pressure or viscosity should decide the technology by itself.

Technology Screening Matrix

Calculating Total Dynamic Head (TDH)

TDH is the specific mechanical energy that the pump must add to the liquid, expressed as head of the pumped liquid.

For pressures in bar and specific gravity SG, a convenient approximation for pressure-head difference is:

Understanding Centrifugal Pump Performance Curves

A complete selection reviews head, efficiency, NPSHR and absorbed power together. The diagrams below use the same illustrative SOH2 80-50-250 dataset so the relationships are easy to compare; final engineering must use the certified performance curve for the selected pump.

Read four performance curves at the same flow

Before comparing different specific speeds, examine a typical pump characteristic with head, shaft input power, efficiency and NPSHR (NPSH3) against flow. Shutoff is at zero flow. BEP is the maximum of the efficiency curve. Head typically falls across the illustrated range, shaft power rises in this example, and the NPSHR curve rises on its measured portion. The y scales for the four quantities are independent; use the separate charts below for actual numerical comparisons.

Best Efficiency Point (BEP)

BEP is the flow at which efficiency is maximum for a specified speed and impeller geometry. It is a useful hydraulic reference, not a universal acceptance band by itself.

Specific Speed & Suction Specific Speed

Similarity parameters explain hydraulic geometry and suction behavior, but their numerical values depend on the definition and unit system. Never compare values from different conventions without conversion.

BEP, POR, AOR & Allowable Flow Range

The operating region is a reliability envelope. A pump can produce the requested head and still be an unacceptable selection if it operates outside its allowable region.

NPSH — Suction Performance & Cavitation Margin

NPSHA is a system characteristic. NPSHR is a manufacturer-supplied pump characteristic; NPSH3 is the tested NPSH associated with a 3% head drop under the applicable test definition.

What Cavitation Means

Cavitation occurs when local pressure falls sufficiently for vapor cavities to form and then collapse as they move into higher-pressure regions. Effects can include noise, vibration, erosion, head loss and instability. Erosion or noise may begin before the conventional 3% head-drop point.

What Reduces NPSHA?

How the 3% head-drop test is performed

At a fixed flow and rotational speed, the test pump is operated at several progressively lower values of available suction head. The head initially remains almost constant, then decreases as cavitation affects the passages. The NPSHA at a 3% reduction in the reference head is reported as NPSH3; for a multistage pump, this criterion applies to the first-stage head. The original training material calls this value NPSHR. Here, NPSH3 identifies the test criterion explicitly, while NPSHR remains the manufacturer-specified requirement used for selection.

Insufficient suction head can cause both cavitation erosion and loss of performance. These consequences need separate assessment: preserving most of the measured head does not establish that the impeller is free of damaging cavitation.

Cavitation effects do not all reach their limits at the same NPSH

The following original figure follows erosion, noise and pressure pulsations as NPSHA decreases. It shows why a single head-drop measurement cannot describe all cavitation effects. The severity may change non-monotonically; a quieter condition alone does not prove that erosion has disappeared.

Two limitations of interpreting the head-drop test

The presentation identifies two limitations: the dependence of head breakdown on the vapor-to-liquid specific-volume ratio, v_g/v_f, at the inlet, and the relationship between the measured head loss and cavitation severity. Liquid temperature and thermodynamic properties can therefore change how a water-test result relates to the actual service.

The original reduction chart compares hydrocarbon liquids and high-temperature water, with temperature in °F and head reduction per stage. The next figure compares cavitation tests in different liquids at constant speed and capacity. Together they illustrate a thermodynamic effect, rather than an instruction to subtract a generic correction from every published NPSH curve. Apply a liquid-specific correction only with the manufacturer's validated method and the applicable project requirements.

Why erosion can occur before a 3% head loss

The presentation describes research available in 1984–1986: depending on impeller material, hydraulic design and energy level, cavitation causing a 3% head loss—and even cavitation producing a smaller loss—could cause erosion. A smaller head-drop criterion was consequently proposed as an alternative definition of the required suction head.

Further observations showed that erosion could occur with available NPSH above the 3% head-drop value. Merely redefining the test around a smaller percentage did not establish an erosion-free condition. In the presentation's design discussion, suction specific speed brings related inlet-design characteristics into a common index. It supplements assessment of cavitation and recirculation; it cannot replace a service-specific NPSH margin.

Suction specific speed: definition, units and impeller-eye flow

Suction specific speed is a similarity index describing inlet hydraulic characteristics independently of physical pump size. The source uses the symbol S and bases its charts on the 3% head-drop criterion. To make the US unit convention explicit, the equation below uses Nss.

Nss = n × √Q_eye,BEP / (NPSH3_BEP)^0.75

• n: rotational speed in rpm.
• Q_eye,BEP: flow per impeller eye at BEP, in US gpm. Use total flow for single suction and half the total flow for double suction.
• NPSH3_BEP: the defined 3% head-drop NPSH at BEP, in ft, for the maximum-diameter impeller.

These numerical indices depend on the unit convention; Nss is not a flow rate even though the source associates its values with US gpm. Specific speed Ns uses head per stage, while suction specific speed Nss uses NPSH3. Keep the two indices separate.

Higher suction specific speed and the operating range

The source highlights two design tendencies as suction specific speed increases: a greater separation between incipient-cavitation NPSH and the 3% head-drop NPSH, and a greater tendency toward inlet recirculation. Noise, vibration and impeller erosion can become more significant, especially when the required flow range extends farther from the design condition. These tendencies must be checked against the actual inlet design and operating curves.

The presentation reports historical screening values of 11,000–12,000 in the US convention. It then discusses research indicating that 15,000–17,000 could be used for particular designs and operating ranges. Both ranges are retained here as part of the engineering lesson. They are neither universal current-standard limits nor blanket approval for a selected pump.

The next curve family shows how suction behavior changes across percent rated flow at different suction-specific-speed values. Review the full range rather than only the rated point. The following relationship chart compares specific speed and suction specific speed for different impeller forms; the plotted experience applies to its source population and should not be treated as a general acceptance boundary.

Definition cross-check: Hydraulic Institute — Pump Principles. Project selection also requires the applicable NPSH-margin guidance and the manufacturer's service-specific curves.

System corrections during starting and fast control changes

For normal steady centrifugal-pump flow, the presentation uses the actual operating flow for pipe-friction calculations rather than the pulsation peak-flow method associated with reciprocating pumps. Starting, stopping or rapidly changing flow still requires transient assessment.

Long suction piping and fast-acting control valves can make acceleration head important to instantaneous NPSHA. The source describes transient inlet disturbances, cavitation and pressure shock during starting. Shorter, appropriately designed suction piping and a controlled start or valve sequence may reduce these disturbances; use a pump-specific procedure rather than a universal valve instruction.

The presentation gives 1.5 ft (approximately 0.46 m, rounded to 0.5 m in the source) as an acceleration-head allowance for suction lines shorter than 70 pipe diameters, with further analysis for longer lines. Preserve these as historical preliminary assumptions. Actual acceleration head depends on flow acceleration, line geometry and controls, not length ratio alone.

Choosing the suction margin for the actual system

The source calls for worst-credible NPSHA, including liquid properties, gas, acceleration and system-induced transient reductions. Margin above the required value is intended to account for performance deterioration and cavitation erosion as well as transient conditions.

Its historical recommendations are approximately 15% of NPSHR, with a minimum of 3 ft or about 1 m, potentially increasing to 50% of NPSHR for severe transient/high-energy cases. These examples are preserved here alongside the earlier NPSH explanation. Use the applicable margin guideline and manufacturer requirements for final selection; these figures are not universal acceptance rules.

Choosing the number of pump stages

Stage count is a hydraulic selection decision: match the required head without sacrificing suction performance or attainable efficiency.

The source gives two historical US-specific-speed screening rules: Ns above 500, and above 1,000 when energy consumption is a major concern. These are design heuristics from the teaching material, not universal requirements for all centrifugal pumps. Evaluate the candidate's actual efficiency, duty range and construction.

At fixed flow and speed, increasing head per stage reduces Ns. The presentation considers two ways of increasing Ns or preventing it from becoming too low:

1. Increase rotational speed. This can raise specific speed, but the resulting suction requirement can also increase. Since the system cannot always supply additional NPSHA, acceptable NPSHR and the actual suction margin constrain this approach. Recalculate the indices and review the manufacturer's curves rather than assuming that speed alone improves the selection.
2. Reduce the head developed by each stage. Distribute the required total head over several stages in a multistage pump, or over pumps operating in series. The source describes this as reducing head per eye; use head per stage consistently in the Ns equation. Verify first-stage suction performance and downstream pressure containment.

The target is a pump arrangement with suitable efficiency and acceptable suction performance. The original selection map below relates head and flow to candidate arrangements; it illustrates the trade-off between energy consumption and suction requirements rather than specifying a guaranteed selection.

Operating capacity and hydraulic stability

The actual duty belongs to the combined installation, not to the pump curve alone.

Operating capacity when suction performance changes

The operating flow is determined by the intersection of the pump head curve and the system head curve. Available suction head must satisfy the manufacturer's requirement with the appropriate service margin throughout the expected range.

If NPSHA falls below the required value, cavitation can reduce the head actually developed. The operating point still depends on the intersection of the system curve and the degraded pump curve; it no longer necessarily lies on the unaffected catalog curve. The original figure shows both the pump/system intersection and the available/required NPSH relationship.

A distinct, stable intersection

The presentation describes a clear, unique intersection as the desired operating condition. A continuously rising system curve intersecting a continuously falling pump curve is a common way to achieve it. Stability comes from the interaction of the two curves, rather than from the pump in isolation.

Head separation and controllability

Across the intended operating range, the relationship between pump head and system head must provide usable control authority. At the steady operating point the heads are equal; away from it, their relative slopes and separation determine how an adjustment in resistance or speed changes flow.

A drooping pump characteristic can form a stable system when paired with a suitable system curve. Conversely, multiple intersections or a poorly defined intersection require additional review of branch stability, valve behavior, operating transitions and the control strategy. This is why the original lesson asks the engineer to assess the complete installation.

Practical Pump Selection Workflow

A robust selection is a sequence of feasibility checks followed by engineering ranking — not a single lookup by Q and H.

Pumps in Parallel & Series

Choose the arrangement by reading the combined pump curve against the system curve, then check every operating combination.

Why consider parallel pumps?

The presentation identifies four reasons to share the flow between two or more pumps:

• The required flow is too large for a suitable single pump.
• Available NPSH is low and flow sharing may permit more suitable inlet hydraulics.
• The service includes sustained, wide changes in required flow.
• The driver required for one pump would be too large.

Each branch shares the common suction and discharge headers and develops approximately the same differential head, allowing for branch losses. At a given common head, add the individual flows: Q_total = Q_A + Q_B. The resulting operating point is the intersection of the combined characteristic and the system curve; two pumps do not automatically produce twice the single-pump operating flow.

Dissimilar pumps can share flow poorly

The source advises against parallel operation of dissimilar pumps in regions where one or both characteristics are flat. One unit can remain at zero contribution until the common head falls sufficiently for it to deliver. This makes the usable curve range, individual shutoff heads and check-valve behavior important.

In the original example, pump B contributes no flow until pump A reaches approximately 35% of its BEP flow. With both pumps running, B's individual contribution is approximately 130% of its own BEP flow, where greater NPSHR and power demand can be expected for the illustrated pump. These percentages describe this example; they are not operating limits for every parallel installation.

Why consider pumps in series?

The presentation lists five reasons to share the energy rise between pumps:

• The required energy rise is too high for one suitable pump.
• The available NPSH is low and a suitable first pump or booster arrangement is needed.
• The required system head varies widely.
• The initial pressure is high, requiring a carefully chosen pressure-rated arrangement.
• The driver needed for a single unit would be too large.

Series pumping does not by itself solve inadequate suction conditions at the first pump. The first unit must meet its suction requirements; each downstream unit must withstand its higher inlet and discharge pressures.

Series operation depends on the system curve

Without intermediate leakage, branching or withdrawal, the same flow passes through every series pump. At that flow, add the developed heads: H_total = H_A + H_B.

The original figure compares a flat, high-static-head system with a steep, friction-dominated system. In the flat-system example, one pump cannot overcome the static head, so no forward flow is obtained until the full series arrangement supplies enough head. This is a condition of the illustrated head levels, not a consequence of every flat system curve. In the steep-system example, adding a pump raises the total head and produces an increased operating flow.

For the operating-point and stability explanation, see Duty and hydraulic stability.

Adjusting Pump Performance and Controlling Capacity

Changing the pump characteristic and changing system resistance move the duty point in different ways.

Impeller diameter and blade setting

The source describes reducing the outer impeller diameter in radial/Francis-type and mixed-flow designs, and changing the blade angle in adjustable axial-flow designs. Diameter adjustment is generally used to match a rated duty rather than as a continuous operating control.

As specific speed increases, the range over which performance can be adjusted by diameter alone generally becomes more restricted. The source also notes that trimming can increase NPSHR in some designs, with this concern becoming more pronounced at higher specific speed. Treat that statement as a design-dependent effect: use the selected pump's actual trim and suction curves.

Diameter scaling at constant speed

These are the preliminary diameter relations shown in the presentation. Its comparison indicates that the calculated trimmed performance can be lower than the actual result and gives an empirical correction chart. Both original figures are retained below. The correction belongs to its historical method and design range; it is not a universal correction for all impellers.

Throttling changes system resistance

A discharge control valve increases resistance and moves the intersection along the pump curve toward lower flow. The original example shows reduced pump input power as flow falls, but the valve still dissipates generated head as an additional energy loss. A reduction in power is not universal across radial, mixed and axial designs; review the actual power curve.

Bypass changes process flow while preserving pump flow

With the bypass closed, the greatest flow enters the downstream process in the source arrangement. Opening the bypass diverts more flow through the return path, reducing process delivery while allowing greater total flow through the pump. With substantial bypass opening, very little of the pumped flow may reach the process.

For the illustrated characteristic, greater bypass opening lowers pump head and increases pump flow and power demand. The main benefit is that reducing process demand need not force the pump into damaging low-flow operation. Review the real characteristic: increasing power is not a universal response for every hydraulic design. Also check recycle heating, suction conditions and minimum-flow protection.

Three performance-adjustment routes in the source

• Impeller diameter: generally a fixed adjustment to match the rated duty.
• Rotational speed: shifts the pump characteristic during operation.
• Available NPSH: the source describes a specialized submergence-control approach for saturated liquid.

In that specialized submergence-control discussion, liquid level in a vessel influences the available suction head and hence the delivered flow. The presentation calls the method uncommon and cites applications with NPSH below 6 ft (approximately 1.83 m). This is historical application guidance, not a general instruction to use cavitation as flow control. Ordinary installations must preserve the required suction margin; this approach requires validated pump and process design.

Speed scaling at unchanged impeller diameter

The source describes speed change as the more common performance-adjustment route. It gives N₂/N₁ ≥ 0.5 as the range in which its speed-scaling estimates have acceptable accuracy without an additional correction. Retain that value as the presentation's approximation range, not as a universal allowable minimum speed or an accuracy guarantee.

Apply the relationships to corresponding points on the pump curves. Find the actual new operating point from the unchanged or modified system curve. Verify efficiency, suction performance, driver/VFD limits, cooling and mechanical operating restrictions.

Cross-checks: Hydraulic Institute — Pump Curves; KSB — Impeller Trimming. Original diagrams and historical examples: Petropedam engineering training material.

Speed control, BEP and suction requirement

The presentation highlights two benefits of speed adjustment compared with throttling: the duty can remain closer to the appropriate BEP, and the pump can generate energy closer to the process requirement. It particularly emphasizes potential savings when the required flow varies substantially. These benefits depend on the system curve and duty profile; a high static-head fraction can move the operating point away from the scaled BEP.

For suction performance, the source gives the following historical speed approximation:

Retain the exponent 1.7 as the presentation's empirical approximation, not as a universal NPSHR law. Recheck the manufacturer's suction curves at the new speed and corresponding flow, and apply the service-specific margin.

Operating Limits and the Effects of Varying Flow

Different mechanisms govern different parts of the flow range. Establish continuous and intermittent limits for the actual pump, liquid and operating conditions.

As a centrifugal pump operates across different flows, inlet, outlet, thermal and mechanical effects can each restrict the allowable range. The source emphasizes pump design, liquid properties and rotor energy as the factors determining how strongly each effect matters. The following original overview places these mechanisms on a common flow axis; the marked regions are teaching examples rather than universal alarm settings.

Inlet choking and discharge recirculation

Inlet choking: at high flow, limited passage area between the impeller blades and increased inlet velocity can cause the required suction head to rise sharply. The source associates choking with approximately 105% of BEP flow for high suction specific speed through 130% for low suction specific speed. These are historical comparison values, not a universal allowable-flow band.

Discharge recirculation: secondary and reverse flow at the impeller outlet can wear the shroud fillet, contribute to shroud fracture and produce fluctuating radial and axial thrust, described in the presentation as rotor shuttle. The source places onset around 70% of BEP flow for a low-efficiency design, while the illustrated better designs can place it beyond BEP. Onset and severity require pump-specific assessment.

Suction recirculation and rotor loading

Suction recirculation: reverse flow around the impeller-eye region can produce surging, vibration, cavitation-like noise and impeller erosion. Its relationship with suction specific speed is important. The source compares onset around 50% of BEP flow at low suction specific speed with onset beyond BEP at high suction specific speed. These source values describe design sensitivity rather than a single minimum-flow rule.

Rotor loads: steady and fluctuating hydraulic forces depend on both hydraulic and mechanical design. Rotor deflection may damage seals and disturb shaft/bearing clearances. The source illustrates a rotor-load-limited low-flow region extending from the start of the curve to roughly 50% of BEP flow; the actual limit must come from the chosen design.

Temperature rise at low flow

Energy losses in the pump heat the liquid. As flow decreases, the same heat input can act on less liquid, increasing temperature rise and vaporization risk. Heated liquid may remain liquid in a higher-pressure region but vaporize when internal leakage returns it toward the lower-pressure suction region, reducing developed head.

The original presentation reports the following temperature-rise expression:

Its legend calls H leakage head, η decimal efficiency and C_p specific heat. The factor 778 indicates a US energy-unit conversion. The supplied expression is retained as source notation; its head and heat-accounting basis must be established before calculation. Do not insert SI units into this expression or treat all developed hydraulic head as heat.

For an explicitly defined heat balance, an engineering estimate is ΔT = P_heat / (ṁ × c_p), with heat transferred to the liquid in W, liquid mass flow in kg/s and specific heat in J/(kg·K). Identify the relevant losses and recirculation path. For shutoff or a closed recycle volume, use a transient heat balance and the manufacturer's minimum-flow method.

Continuous and intermittent allowable flow

The source distinguishes continuous and intermittent operation. A brief permitted excursion is not approval for sustained operation. The original wear-rate figure shows why operation away from the favorable region can shorten service life, with the trend depending on energy level.

Choosing a minimum-flow bypass

A bypass is commonly used to prevent the pump from entering the lower intermittent operating region. If the continuous and intermittent minimum-flow limits are close, or if extended operation below the continuous limit would otherwise occur, the source calls for sizing the bypass to preserve the minimum continuous flow.

Defining the range is difficult because the mechanisms overlap and off-BEP behavior varies between designs. A limiting phenomenon for one pump may not govern another. Establish the governing thermal, hydraulic and mechanical limits rather than copying a percentage.

Historical flow-limit guidance retained from the source

Which mechanism sets the minimum?

• Rotor loads and temperature rise commonly govern the intermittent minimum in the source discussion.
• If the thermal limit extends beyond the otherwise allowable continuous minimum, the thermal limit becomes the governing continuous minimum.
• In high-speed single- or multistage designs, rotor loads can govern both continuous and intermittent minimum flow.
• The required head rise for stable operation, motor power in high-specific-speed designs, and the need to handle liquid containing gas bubbles can also determine the required bypass flow.

Combine these constraints with the manufacturer's permitted operating duration, POR/AOR, suction margin, seal cooling and process requirements. The historical percentages above preserve the teaching material; they do not replace manufacturer operating limits.

Further off-design checks

Three radial-load mechanisms

• Steady radial thrust: nonuniform pressure around a single volute during off-design operation, asymmetric pressure distribution in a double volute, or an eccentric diffuser can create a net radial force.
• Fluctuating radial loads: secondary flow and pressure pulsations at the impeller outlet can generate time-varying forces.
• Low-frequency rotating forces: diffuser stall can create a rotating hydraulic disturbance.

Viscosity changes the hydraulic performance

The source identifies greater frictional losses, thicker boundary layers that change effective passage geometry, reduced developed head and efficiency, and increased power demand. It notes stronger efficiency penalties at low specific speed. The original figure compares performance at different viscosities; use a recognized viscosity-correction method and verified liquid properties at operating temperature.

The presentation states a historical screening ceiling of 500 SSU for centrifugal pumping. This value is retained as source guidance, not a universal prohibition. SSU is temperature-dependent efflux time and is not numerically interchangeable with cSt. Technology choice requires viscosity at the actual temperature, hydraulic corrections, efficiency and lifecycle assessment.

Entrained gas changes the head curve

The source chart compares 1–6% gas by volume with gas-free liquid and shows changing developed head and minimum-capacity behavior. The effect depends on hydraulic design, gas fraction at suction conditions, pressure and liquid properties; the plotted percentages are test comparisons rather than generic gas-handling ratings. Distinguish free/entrained gas from dissolved gas and cavitation vapor.

Cross-check: Hydraulic Institute — NPSH and operating regions. The applicable operating-region guidance and manufacturer limits govern the final selection. Original diagrams and historical examples: Petropedam training material.

Petropedam Project References

Selected company project references supplied by Petropedam, spanning Oil & Gas, Refinery, Petrochemical, Mining and Water services.

Selected Project Highlights

Full project reference list and current company totals are available from Petropedam upon request.

Pump Selection Checklist

Use this checklist before a pump is released for quotation or final specification.

Standards, References & Engineering Basis

The original Petropedam PowerPoint provides the training framework; edition-specific rules and legacy rules-of-thumb have been reviewed against current published information.

• API 610, 13th Edition — 29 June 2026 — Centrifugal Pumps for Petroleum, Petrochemical and Natural Gas Industries (API Standards Plan).
• ANSI/HI 9.6.1-2024 — Rotodynamic Pumps Guideline for NPSH Margin.
• ANSI/HI 9.6.3-2024 — Rotodynamic Pumps — Guideline for Operating Region(s).
• ANSI/HI 9.6.7-2021 — Rotodynamic Pumps — Guideline for Effects of Liquid Viscosity on Performance.
• ANSI/HI 9.6.6-2022 — Rotodynamic Pumps for Pump Piping.
• ANSI/HI 9.8-2024 — Rotodynamic Pumps for Pump Intake Design.
• API 674, 3rd Edition (2010) — published reciprocating positive-displacement pump edition identified in API's catalog; Edition 4 is listed by API as in development/editing.
• API 676, 4th Edition — 2 February 2022 — Positive Displacement Pumps — Rotary.

Frequently Asked Questions