1. Overview
Reservoir fluid analysis is a comprehensive laboratory study conducted to characterize the composition, phase behavior, and thermophysical properties of reservoir fluids under in-situ temperature and pressure conditions.
The objective is to understand how the fluid behaves during production, injection, and enhanced oil recovery (EOR) operations—providing critical input for reservoir simulation, production strategy design, and facility engineering.
The analysis determines fundamental parameters such as bubble-point or dew-point pressure, gas–oil ratio (GOR), density, viscosity, formation volume factor, and phase compositions across a range of pressures and temperatures.
2. Sample Collection and Preparation
Representative fluid samples (oil, gas, or condensate) are collected from the wellhead, separator, or downhole sampling tools using high-pressure single-phase cylinders to prevent gas breakout.
Prior to testing, samples are recombined in the laboratory to reproduce the original reservoir composition according to field GOR and production conditions.
All sample-handling operations are performed under isothermal and isobaric control to ensure data integrity.
3. Experimental Procedures
Reservoir fluid analysis typically includes the following laboratory experiments:
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Constant Composition Expansion (CCE):
The recombined fluid is expanded stepwise under isothermal conditions to determine bubble-point (for oils) or dew-point (for gas condensates) pressure, and to observe phase changes during depletion. -
Differential Liberation Test (DL):
Simulates the pressure–volume–temperature (PVT) behavior of oil during production, determining formation volume factor (Bo), solution GOR, and oil shrinkage as pressure decreases. -
Constant Volume Depletion (CVD):
Applied to condensate and volatile oil systems to study retrograde condensation, yielding liquid dropout curves and composition changes during depletion. -
Viscosity and Density Measurement:
Dynamic and kinematic viscosities are measured using rolling-ball or capillary viscometers, while density and compressibility are determined under reservoir P–T conditions. -
Gas and Liquid Composition Analysis:
Performed by gas chromatography (GC) or mass spectrometry, identifying major hydrocarbon groups (C₁–Cₙ) and non-hydrocarbon gases (CO₂, N₂, H₂S). -
Swelling Test (CO₂ or Gas Injection Study):
Determines the solubility, swelling factor, and miscibility behavior of reservoir oil upon gas injection, often used in CO₂-EOR and compositional modeling. -
Asphaltene/Wax Onset Detection:
Using Near-Infrared (NIR), Raman, or microscopic imaging systems, the onset pressure and temperature for solid precipitation are recorded to assess flow assurance risks.
4. Data Interpretation and Deliverables
The experimental results provide the following key outputs:
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Phase envelopes (P–T diagrams) and critical point identification;
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Saturation pressure, viscosity, and density trends;
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CO₂ solubility and oil swelling ratios;
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Asphaltene Onset Pressure (AOP) and Wax Appearance Temperature (WAT);
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Compositional data tables for use in reservoir simulation models (EOS tuning).
These results are essential for predicting reservoir performance under natural depletion, gas injection, or miscible flooding scenarios.
5. Applications
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Reservoir engineering design (material balance, compositional simulation).
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Enhanced Oil Recovery (EOR) optimization and miscibility prediction.
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Flow assurance studies for wax/asphaltene deposition and hydrate control.
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Surface facility design, separator sizing, and phase management.
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CCUS and CO₂ storage behavior evaluation.
6. Summary
Reservoir fluid analysis bridges the gap between reservoir thermodynamics and field performance.
By integrating PVT, compositional, and phase-behavior data, engineers can accurately model production behavior, optimize EOR strategies, and manage CO₂ injection and storage processes under complex reservoir conditions.