Injection & Stripping Point Hydraulics Fundamentals

1. Injection & Stripping Concepts

Liquid pipelines frequently have points along their route where fluid is added or removed. These midpoint flow changes fundamentally alter the hydraulic conditions downstream of the connection, and the pipeline must be designed to handle the different flow regimes on either side of each injection or stripping point.

What Is Injection?

Injection is the addition of fluid into a pipeline at a location between the inlet and the outlet. Common injection scenarios include:

• Produced water injection: Water from well separators is injected into a gathering pipeline for transport to a disposal facility.
• Chemical injection: Drag reducing agents (DRAs), corrosion inhibitors, or scale inhibitors are injected at metered rates along the pipeline.
• Crude oil blending: A lighter or heavier crude stream is injected to achieve a target blend specification at the delivery point.
• NGL injection: Natural gas liquids (condensate, butane) are injected into a crude oil pipeline to reduce viscosity or meet vapor pressure specifications.

What Is Stripping?

Stripping is the removal of fluid from a pipeline at an intermediate point. Common stripping scenarios include:

• NGL extraction: Heavier hydrocarbons are drawn off at a processing facility connected to the mainline.
• Water removal: Free water accumulated at low points is removed through drip legs or separator connections.
• Product offtake: A delivery lateral draws product from the mainline to serve a local customer or terminal.
• Partial diversion: Flow is split between a mainline continuation and a branch pipeline at a tee connection.

Impact on Pipeline Design

The critical consequence of any injection or stripping point is that hydraulic conditions differ on either side. Upstream of the point, the pipeline carries one flow rate with one set of fluid properties. Downstream, both the flow rate and potentially the fluid properties are different. This means the pipeline must be analyzed as two (or more) separate hydraulic sections joined at the injection or stripping point.

Two-Section Analysis Approach

The standard approach divides the pipeline at each injection or stripping point and treats each segment independently. The upstream section is analyzed with the upstream flow rate and fluid properties. The downstream section uses the modified flow rate and, if the injected fluid differs from the mainline fluid, the blended properties. The pressure at the injection point serves as the boundary condition linking the two sections.

2. Fluid Mixing & Property Changes

When the injected fluid has different properties than the mainline fluid, the blended stream downstream has new density, specific gravity, and viscosity values. Accurate calculation of these mixed properties is essential because they directly affect friction factor, pressure drop, and velocity in the downstream section.

Volume-Weighted Specific Gravity

For miscible fluids (such as blending two crude oils or injecting condensate into crude), the mixed specific gravity is calculated by volume-weighted averaging:

Where:

• Q₁ = mainline volumetric flow rate (bbl/day or gpm)
• SG₁ = specific gravity of the mainline fluid
• Q₂ = injected (or stripped) volumetric flow rate
• SG₂ = specific gravity of the injected fluid

For stripping, Q₂ is negative (fluid removed), and the formula still applies provided the stripped fluid has the same composition as the mainline fluid. If a specific component is preferentially removed (such as water from an oil-water mixture), the stripped fluid’s SG must be specified independently.

Mixed Density Calculation

The mixed density follows directly from the mixed specific gravity:

Where ρ_water = 62.4 lb/ft³ at standard conditions, or adjusted for operating temperature. This mixed density is used in the Darcy-Weisbach equation for the downstream pressure drop calculation.

Viscosity Blending

Viscosity blending is more complex than density blending because viscosity does not mix linearly. Two common approaches are used:

• Simplified linear blend: μ_mix = (Q₁ × μ₁ + Q₂ × μ₂) / (Q₁ + Q₂). This is adequate when the two fluids have similar viscosities (within a factor of 2–3).
• Refutas method: Converts each viscosity to a Viscosity Blending Index (VBI), blends the indices linearly by volume fraction, then converts back. This method is preferred when blending fluids with significantly different viscosities, such as a light condensate into heavy crude.

Temperature Effects on Mixing

If the injected fluid is at a different temperature than the mainline fluid, the mixed temperature is estimated by an energy balance. In practice, for liquid pipelines operating near ambient ground temperature, the temperature difference between the mainline and the injected stream is often small enough that an arithmetic average weighted by mass flow rate provides an acceptable estimate.

When Mixing Assumptions Break Down

The volume-weighted blending approach assumes the fluids are fully miscible and mix uniformly in the pipe cross-section. This assumption fails for:

• Oil-water systems: Immiscible fluids form dispersions or stratified flow rather than a homogeneous mixture. Effective mixture viscosity depends on the emulsion type (oil-in-water or water-in-oil) and the inversion point.
• Gas-liquid injection: Injecting gas into a liquid pipeline creates two-phase flow, requiring multiphase flow correlations rather than single-phase mixing rules.
• High-viscosity ratios: When the viscosity ratio exceeds about 10:1, achieving uniform mixing requires significant pipe lengths or static mixers downstream of the injection point.

3. Hydraulic Analysis Method

The hydraulic analysis of a pipeline with injection or stripping points follows a structured approach that divides the system at each flow change location and applies standard single-phase friction calculations to each segment independently.

Step 1: Split the Pipeline into Sections

Identify all injection and stripping points along the route. Each point defines a boundary between two hydraulic sections. For a pipeline with one injection point, this creates an upstream section (inlet to injection point) and a downstream section (injection point to outlet). Multiple injection or stripping points create multiple sections, each analyzed sequentially.

Step 2: Upstream Section — Standard Single-Fluid Analysis

The upstream section is analyzed using the mainline flow rate and fluid properties. Apply the Darcy-Weisbach equation for friction pressure loss:

Where f is the Darcy friction factor (from the Moody chart or Colebrook-White equation), L is the upstream section length, D is the pipe inside diameter, ρ is the fluid density, and V is the flow velocity. Include elevation head changes: ΔP_elev = ρ × g × Δz.

Step 3: Injection Point — Mass and Volume Balance

At the injection point, perform the flow balance:

• Volume balance: Q_downstream = Q_upstream + Q_injected (positive for injection, negative for stripping)
• Mass balance: m_downstream = m_upstream + m_injected = ρ₁Q₁ + ρ₂Q₂
• Property calculation: Compute SG_mix, ρ_mix, and μ_mix using the blending formulas from Section 2

The pressure at the injection point is the boundary condition. It equals the inlet pressure minus the upstream friction and elevation losses: P_injection = P_inlet − ΔP_f,upstream − ΔP_{elev,upstream}.

Step 4: Downstream Section — Mixed Properties

The downstream section uses the combined flow rate, mixed density, and mixed viscosity. Recalculate the Reynolds number using the downstream conditions:

Determine the new friction factor from the updated Reynolds number, then calculate the downstream friction pressure loss and elevation changes. The outlet pressure is: P_outlet = P_injection − ΔP_f,downstream − ΔP_{elev,downstream}.

Step 5: Construct the Complete Pressure Profile

Combine the upstream and downstream pressure profiles to create a continuous pressure-versus-distance curve for the entire pipeline. The profile will show a change in slope at the injection point — steeper if injection increases the flow rate (higher friction downstream) or shallower if stripping reduces it.

Separate Friction Factor for Each Section

Because the Reynolds number changes at the injection point, the friction factor changes as well. In turbulent flow (the typical regime for liquid pipelines), a higher downstream flow rate increases the Reynolds number and slightly decreases the friction factor, but the net effect is higher friction loss because the velocity increase dominates. The opposite occurs for stripping: reduced flow lowers velocity and friction loss per unit length.

4. Velocity & Flow Effects

The change in flow rate at an injection or stripping point directly affects the fluid velocity in the downstream section. Velocity is a critical design parameter because it governs erosion potential, pressure drop rate, and surge behavior.

Velocity Change at the Injection Point

For a constant-diameter pipeline, velocity is proportional to volumetric flow rate. The downstream velocity after injection is:

Where A is the pipe cross-sectional flow area (πD²/4). The percentage change in velocity is a useful design metric:

For stripping, the velocity decreases by the same percentage relationship. A 20% injection rate (Q_injected = 0.20 × Q_upstream) produces a 20% increase in downstream velocity.

Erosional Velocity Check

Both the upstream and downstream sections must be checked against erosional velocity limits. API RP 14E provides the widely used erosional velocity formula for mixed-phase flow, but for single-phase liquid pipelines, the practical erosional limit is typically 10–15 ft/s for carbon steel pipe, depending on the fluid and whether solids are present:

• Clean liquids (no solids): Maximum velocity of 10–15 ft/s is common practice.
• Liquids with sand or solids: Maximum velocity of 5–8 ft/s to limit erosion at elbows, tees, and restrictions.
• Corrosive service: Lower velocity limits (3–6 ft/s) may apply where corrosion-erosion synergy is a concern.

If the downstream velocity after injection exceeds the erosional limit, the pipeline diameter must be increased downstream of the injection point, or the injection rate must be reduced.

Transition Losses at the Injection Tee

The injection tee itself introduces minor losses due to the merging of two flow streams. These losses are characterized by a loss coefficient (K-factor) applied to the velocity head. Typical K-values for tee junctions depend on the flow split ratio and the geometry (reducing tee, full-bore tee, or wye connection). Crane TP-410 provides detailed K-factors for various tee configurations. For preliminary design, a K-factor of 0.5–1.5 applied to the downstream velocity head is a reasonable estimate for the combined tee loss.

Surge and Transient Considerations

Injection and stripping points are locations where transient pressure events can originate. Rapid changes in the injection rate — such as a pump trip on an injection line or a sudden valve closure on a stripping lateral — create pressure waves that propagate through the pipeline. Key considerations include:

• Injection pump trip: Sudden loss of injection flow causes a rapid velocity decrease downstream, generating a pressure rise (water hammer) that propagates toward the outlet.
• Stripping valve closure: Suddenly stopping the offtake flow increases the mainline flow downstream, causing a pressure drop upstream and a pressure rise downstream of the stripping point.
• Check valve slam: If the injection line has a check valve, rapid flow reversal can cause check valve slam and associated pressure spikes at the tee connection.

Design Guidelines for Velocity Changes

5. Design Applications

Injection and stripping point hydraulics apply across a wide range of pipeline systems. Each application has specific design considerations that build on the fundamental analysis methods described in the preceding sections.

Produced Water Disposal Pipelines

Produced water gathering systems often have multiple injection points where field separators discharge into a common trunk line. Each injection point increases the mainline flow rate, creating a progressively increasing velocity profile. The pipeline diameter may need to increase (telescope) at points where cumulative injection volumes push the velocity above acceptable limits. Water quality (solids loading, dissolved gases) affects both erosional velocity limits and corrosion allowances.

NGL Injection into Crude Pipelines

Injecting lighter NGL components (butane, natural gasoline) into a crude oil pipeline reduces the blend viscosity and can improve pumpability. However, the lighter components also reduce the blend density and increase vapor pressure. The downstream section must be checked against the pipeline’s vapor pressure limit to avoid two-phase flow conditions. The mixed viscosity is typically calculated using the Refutas method due to the large viscosity difference between crude oil and NGL components.

Chemical Injection (DRA, Corrosion Inhibitors)

Chemical injection rates are typically very small relative to the mainline flow (often less than 0.1% by volume). The volumetric impact on downstream hydraulics is negligible, so the primary analysis concerns are ensuring adequate injection pressure to overcome mainline pressure at the injection point and proper atomization or dispersion of the chemical into the flowing stream. Drag reducing agents (DRAs) are a special case: despite negligible volumetric contribution, they reduce the effective friction factor downstream by 20–60%, significantly altering the pressure profile.

Crude Oil Blending Operations

Pipeline blending injects one crude grade into another to produce a specification blend at the delivery terminal. The injection rate is typically 10–40% of the mainline flow, making the two-section hydraulic analysis essential. In addition to the standard hydraulic calculations, blending operations require tracking the blend interface and verifying that the downstream mixed properties (API gravity, sulfur content, viscosity) meet the target specification. Inline static mixers are often installed downstream of the injection tee to ensure homogeneous blending within a short distance.

Pipeline Offtake and Delivery Points

Every delivery lateral or offtake connection is a stripping point that reduces the mainline flow downstream. For pipelines with multiple delivery points, the cumulative flow reduction creates a progressively decreasing velocity profile. The downstream sections may operate at very low velocities, potentially causing issues with water dropout, wax deposition, or sediment accumulation in low spots. Minimum velocity requirements (typically 2–3 ft/s for waxy crudes) must be checked for the final sections of multi-delivery pipelines.

Standards and References

• Crane TP-410: Flow of Fluids Through Valves, Fittings, and Pipe — K-factors for tee junctions, friction loss calculations, and equivalent length methods for fittings
• API RP 14E: Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems — erosional velocity formula and velocity limits for production piping
• ASME B31.4: Pipeline Transportation Systems for Liquids and Slurries — design requirements for liquid pipeline systems including branch connections and tee details
• API MPMS Ch. 12: Manual of Petroleum Measurement Standards — calculation of petroleum quantities including density and volume correction factors for blended streams
• ASTM D7152: Standard Practice for Calculating Viscosity of a Blend of Petroleum Products — Refutas viscosity blending method