Separator Test (Multistage Flash Separation)

PVT Analysis of Reservoir Fluids › 3. Separation Tests (Multistage / Flash Separation)

Reviewed by Coretest reservoir-fluids engineers · Updated 21 June 2026

Purpose↑ Contents

The multistage separation test answers a deceptively simple but economically critical question: when reservoir oil is produced to the surface and processed through a real train of field separators, how much stock-tank oil and how much gas actually arrive at the sales point, and what are their properties? Differential Liberation (DL) describes how gas evolves inside the reservoir as a single continuous process at reservoir temperature; it does not describe the surface. The separation test fills that gap. It quantifies:

• The producing gas-oil ratio (GOR) that the surface facility will actually deliver, broken down stage by stage.
• The shrinkage of reservoir oil down to stock-tank conditions, expressed as the formation volume factor of oil at the bubble point referenced to stock-tank oil, \( B_{ob} \) (separator basis).
• The API gravity and density of the marketable stock-tank oil.
• The split of evolved gas between high-pressure, intermediate, and low-pressure (stock-tank) streams, which drives compressor sizing, vapor-recovery design, and the optimum separator pressure that maximizes liquid recovery.

Crucially, the separation test provides the conversion factors used to correct laboratory DL/CCE data to field separator conditions, so that the \( B_o \) and \( R_s \) curves fed into reservoir simulation and reserves calculation reflect the chosen surface configuration rather than a single flash.

Physical principle↑ Contents

A separator is an equilibrium flash stage: a feed stream at pressure \( p \) and temperature \( T \) is allowed to split into a saturated liquid phase and an equilibrium vapor phase that obey the equal-fugacity condition for every component \( i \):

$$f_i^L (p,T,x) = f_i^V (p,T,y)$$

which is summarized by the equilibrium ratio (K-value):

$$K_i = \frac{y_i}{x_i}$$

where \( x_i \) is the mole fraction of component \( i \) in the liquid and \( y_i \) is the mole fraction in the vapor. \( K_i \) is a strong function of pressure and temperature; lowering pressure raises \( K_i \) for the volatile components and drives them into the vapor.

For a feed of total composition \( z_i \) flashed at a given \( p \) and \( T \), the vapor mole fraction \( V \) (moles vapor per mole feed) is found from the Rachford-Rice material balance:

$$\sum_i \frac{z_i (K_i - 1)}{1 + V (K_i - 1)} = 0$$

with phase compositions then \( x_i = \dfrac{z_i}{1 + V (K_i - 1)} \) and \( y_i = K_i x_i \).

Multistage separation is the sequential application of this flash. The saturated liquid leaving stage \( n \) becomes the feed \( z_i \) to stage \( n+1 \), which operates at a lower pressure. Because each stage strips a different slate of components, the cumulative gas released and the final liquid volume depend on the entire pressure-temperature staging path, not just the endpoints. Staging matters because retaining intermediate components (\( C_3 \) to \( C_6 \)) in the liquid through controlled, stepwise pressure reduction yields more stock-tank oil than a single violent flash to atmospheric conditions; this is the basis for the existence of an optimum first-stage separator pressure.

Key derived quantities:

• Stage GOR: the standard-condition gas volume liberated at a stage divided by the stock-tank oil volume.
• Total (producing) GOR: \( \text{GOR}_{sep} = \sum_n \dfrac{(V_{gas,std})_n}{V_{stock\_tank\_oil}} \), the sum over all stages per unit stock-tank oil.
• Oil formation volume factor at the bubble point on a separator basis: \( B_{ob} = \dfrac{V_{oil}(p_b, T_{res})}{V_{stock\_tank\_oil}} \), the volume of saturated reservoir oil at the bubble point that yields one unit volume of stock-tank oil after passing through the specified separator train.
• Shrinkage factor: \( b = \dfrac{1}{B_{ob}} \).

Symbols: \( p \) = pressure; \( T \) = temperature; \( T_{res} \) = reservoir temperature; \( p_b \) = bubble-point pressure; \( z_i, x_i, y_i \) = feed, liquid, vapor mole fractions of component \( i \); \( K_i \) = equilibrium ratio; \( V \) = vapor mole fraction per mole feed; \( V_{gas,std} \) = gas volume corrected to standard conditions (e.g. \( 15.56\ \text{C} \) and \( 101.325\ \text{kPa} \), i.e. \( 60\ \text{F} \) and \( 14.696\ \text{psia} \)); \( V_{oil} \) = oil volume at stated \( p,T \); \( V_{stock\_tank\_oil} \) = final liquid volume at stock-tank conditions; \( B_{ob} \) = oil FVF at bubble point (separator basis); \( \rho \) = density; \( m \) = mass.

Apparatus and conditions↑ Contents

The test starts from a representative reservoir fluid sample restored to single-phase conditions in a high-pressure, high-temperature PVT cell (typically a windowed or blind cell with a calibrated piston/positive-displacement pump for accurate volume metering). The sample is brought to reservoir temperature \( T_{res} \) and to its bubble-point pressure \( p_b \), so the feed to the first separator is saturated oil at reservoir conditions.

The fluid is then expelled in a controlled manner through a laboratory separator train. Each stage is an independent vessel held at a fixed, prescribed pressure and temperature:

• A typical two-stage scheme: stage 1 (primary/high-pressure separator) at an elevated pressure and a temperature near field conditions; stage 2 = stock tank at near-atmospheric pressure and standard temperature.
• A three-stage scheme inserts an intermediate-pressure separator between them (high, medium, low pressure).

The liberated gas from each stage is measured volumetrically (or by mass) and analyzed by gas chromatography; the residual liquid is passed forward to the next stage. The last stage discharges the stock-tank oil, whose volume, density/API, and (optionally) composition are measured at standard conditions. Stage pressures and temperatures are held constant; the variable being studied is the staging configuration (how many stages and at what pressures), and the test is frequently repeated for several candidate first-stage pressures to locate the optimum.

Procedure↑ Contents

1. Validate and restore the sample: check opening/bubble-point pressure against field data, heat to reservoir temperature \( T_{res} \), and homogenize the single-phase oil above \( p_b \).
2. Set the separator train: configure each separator to its assigned pressure and temperature (e.g. stage 1 high \( p \), stage 2 medium \( p \), stage 3 low \( p \) / stock tank), and zero/calibrate all gas meters and the liquid volume reference.
3. Bring the cell to the bubble point: reduce cell pressure to \( p_b \) at \( T_{res} \) so the charge is saturated oil; record the cell volume \( V_{oil}(p_b, T_{res}) \).
4. Flash to stage 1: displace the saturated oil into the first separator at its set \( p \) and \( T \). Allow full equilibration; the gas cap in the separator separates from the liquid.
5. Measure stage 1 outputs: meter the liberated gas, correct it to standard conditions, sample it for GC, and record the residual liquid volume and (where applicable) liquid density at stage 1 conditions.
6. Transfer to stage 2: move the stage-1 liquid into the second separator at its lower pressure and temperature; equilibrate.
7. Measure stage 2 outputs: meter and correct the gas liberated, sample for GC, and record the residual liquid volume.
8. Repeat for stage 3 (if present): transfer the liquid, equilibrate, meter and analyze the gas, record liquid volume.
9. Discharge stock-tank oil: collect the final liquid at stock-tank (standard) conditions; measure \( V_{stock\_tank\_oil} \), its mass, and its density/API gravity at the reference temperature (correcting to standard temperature as required).
10. Total the gas: sum all stage gas volumes (corrected to standard conditions) to obtain the cumulative liberated gas per unit stock-tank oil.
11. Compute and tabulate: calculate stage GORs, total GOR, \( B_{ob} \) (separator basis), shrinkage, and stock-tank density/API.
12. Repeat the train for alternate first-stage pressures to map the optimum-separator-pressure study, if requested.

Measured parameters↑ Contents

At each separator stage: - Volume of gas liberated, metered then corrected to standard conditions, \( (V_{gas,std})_n \). - Composition of the liberated gas by gas chromatography (yielding \( y_i \) and gas specific gravity / molecular weight). - Residual liquid volume leaving the stage (and stage liquid density where measured). - Stage pressure and temperature (the controlled set points, logged for QA).

At the final (stock-tank) stage: - Stock-tank oil volume at standard conditions, \( V_{stock\_tank\_oil} \). - Stock-tank oil mass \( m_{oil} \) and density \( \rho_{sep} \), hence API gravity. - Optionally, stock-tank oil composition.

At the reservoir reference point: - Saturated oil volume at the bubble point and reservoir temperature, \( V_{oil}(p_b, T_{res}) \).

Calculated / derived parameters↑ Contents

Stage gas-oil ratio (per stage \( n \)), gas at standard conditions per unit stock-tank oil:

$$\text{GOR}_n = \frac{(V_{gas,std})_n}{V_{stock\_tank\_oil}}$$

Total producing (separator) GOR, summed over all stages:

$$\text{GOR}_{sep} = \sum_n \frac{(V_{gas,std})_n}{V_{stock\_tank\_oil}} = \sum_n \text{GOR}_n$$

This is the laboratory analogue of the field solution gas-oil ratio at the bubble point, \( R_{sb} \), on a separator basis.

Oil formation volume factor at the bubble point, separator basis:

$$B_{ob} = \frac{V_{oil}(p_b, T_{res})}{V_{stock\_tank\_oil}} \quad [\text{rm}^3/\text{sm}^3 \text{ or rbbl/STB}]$$

Shrinkage factor:

$$b = \frac{1}{B_{ob}} = \frac{V_{stock\_tank\_oil}}{V_{oil}(p_b, T_{res})}$$

Density of the separator/stock-tank oil:

$$\rho_{sep} = \frac{m_{oil}}{V_{oil}(p_{sep}, T_{sep})}$$

evaluated at stock-tank conditions for the marketable oil density; the same definition applied at an intermediate stage gives that stage's liquid density. API gravity follows from the stock-tank density at \( 60\ \text{F} \):

$$\text{API} = \frac{141.5}{\text{SG}_{oil}} - 131.5, \quad \text{with}\ \text{SG}_{oil} = \frac{\rho_{oil}}{\rho_{water}}\ (\text{both at } 60\ \text{F})$$

Separator-basis FVF and GOR are then used as conversion (consistency) factors to adjust the differential-liberation \( B_{od} \) and \( R_{sd} \) curves to the chosen surface train, typically via:

$$B_o(p) = B_{od}(p) \times \frac{B_{ob}}{B_{odb}}$$

$$R_s(p) = R_{sb} - [R_{sdb} - R_{sd}(p)] \times \frac{B_{ob}}{B_{odb}}$$

where the subscript \( d \) denotes differential-liberation values and the subscript \( db \) the differential value at the bubble point; \( B_{ob} \) and \( R_{sb} \) come from the separator test.

Reporting and typical curves↑ Contents

The primary deliverable is a separator-test table, one row per stage, reporting: stage pressure and temperature, GOR per stage, gas specific gravity and gas composition per stage, stage liquid shrinkage, and the cumulative totals (total GOR, \( B_{ob} \), stock-tank API/density). A separate summary lists the single set of bubble-point reference properties (\( B_{ob} \), \( R_{sb} \), stock-tank density/API) for the recommended train.

When an optimum-separator-pressure study is run, the key plots are: - Stock-tank oil gravity (API) versus first-stage separator pressure. - Total GOR versus first-stage separator pressure. - \( B_{ob} \) (or oil shrinkage) versus first-stage separator pressure.

These curves typically show that as first-stage pressure rises from atmospheric, GOR and shrinkage first fall (more liquid retained, gravity climbs) to a minimum and then rise again. The pressure at the minimum GOR and minimum \( B_{ob} \), equivalently the maximum stock-tank liquid yield and maximum API, identifies the optimum primary separator pressure. The reservoir/facilities engineer reads the optimum from this minimum, then reports the matching \( B_{ob} \), \( R_{sb} \), and stock-tank gravity as the design basis. The stage-by-stage gas split is read directly from the GOR-per-stage column to size compressors and vapor recovery.

Practical notes and pitfalls↑ Contents

• Sample representativeness governs everything: an under-restored or contaminated sample (drilling-mud filtrate, lost light ends) biases GOR and \( B_{ob} \); confirm the measured opening/bubble-point pressure against field measurements before proceeding.
• Reach true equilibrium at each stage. Insufficient residence/agitation time leaves the liquid supersaturated, under-reports liberated gas, and inflates the apparent stock-tank volume. Rock/agitate and let pressure stabilize before metering.
• Always correct gas volumes to a single, stated standard condition (e.g. \( 60\ \text{F} \) and \( 14.696\ \text{psia} \)) and apply gas compressibility (\( Z \)) when converting metered to standard volumes; mixing reference bases is a common and serious error.
• Mind the temperature of the stock-tank measurement. Stock-tank oil volume must be reported at standard temperature; volumetric thermal correction of the final liquid is a frequent source of \( B_{ob} \) error.
• The separator path is irreversible and history-dependent: results for a two-stage train cannot be inferred by simply adding flashes from a three-stage run. Each candidate configuration must be physically run (or rigorously EOS-modeled) and matched to the field's actual vessels and set points.
• Watch dead volume and transfer losses. Liquid hold-up in transfer lines and valves between stages, and gas trapped in dead volumes, shift both the liquid carry-forward and the metered gas; account for or minimize them.
• Modern PVT practice favors mercury-free cells (piston/positive-displacement metering) for safety and to avoid mercury-amalgam contamination of samples; legacy mercury-displacement procedures require strict handling and introduce capillary/meniscus reading uncertainty.
• Distinguish flash (separator) from differential data. Reservoir simulation requires separator-basis \( B_{ob} \) and \( R_{sb} \); feeding raw differential-liberation values without the separator correction over- or under-states oil-in-place and recoverable volumes.
• Gas sampling and GC quality control matter: ensure single-phase gas sampling at each stage and reconcile recombined stream composition against the original reservoir-fluid composition as a material-balance check.