Core Flooding Experiment

CO2 Flooding System for EOR Testing

The CO₂ flooding experiment was conducted to investigate the oil recovery performance, phase behavior, and solid deposition phenomena under reservoir conditions. The study simulated the injection of carbon dioxide into a representative crude oil system to evaluate miscibility development, displacement efficiency, and potential formation of asphaltene or wax precipitates.

1. Experimental Setup

The experiment utilized a high-pressure core flooding/PVT apparatus capable of operating up to 100 MPa and 150 °C, equipped with precise pressure and temperature control. The system included:

  • A high-pressure injection pump for CO₂ delivery at controlled flow rates;

  • A stainless-steel core holder with a confining pressure system simulating reservoir overburden stress;

  • Temperature-controlled oven to maintain reservoir temperature;

  • Differential pressure transducers and back-pressure regulators for monitoring flow and pressure profiles;

  • Online sampling ports and a gas–liquid separator for post-flood fluid collection and analysis.

2. Procedure

  1. Core Preparation: A cleaned and dried core plug (sandstone or shale) was saturated with brine and crude oil to establish initial reservoir saturation conditions. Porosity and permeability were determined prior to flooding.

  2. Baseline Waterflooding: Brine was injected to establish a reference recovery and to simulate secondary recovery conditions.

  3. CO₂ Injection: CO₂ was introduced at incremental pressures until the desired reservoir pressure was achieved. The injection was carried out under constant rate or constant pressure mode, depending on the test design.

  4. Production Monitoring: Produced fluids were collected, and the volumes of oil, gas, and water were recorded continuously. Gas–oil ratios (GOR), differential pressure, and recovery efficiency were measured.

  5. Post-Flood Analysis: Recovered samples were analyzed for CO₂ solubility, viscosity, and asphaltene or wax content using NIR, Raman, and visual inspection through optical or IR high-pressure cells.

3. Experimental Objectives

  • Determine incremental oil recovery compared with waterflooding;

  • Evaluate CO₂ miscibility development and minimum miscibility pressure (MMP);

  • Observe phase behavior changes and solid precipitation phenomena during injection;

  • Quantify CO₂ dissolution and storage capacity in the oil phase.

4. Data and Interpretation

The results included:

  • Cumulative oil recovery curves and recovery factor vs. pore volume injected (PV);

  • Pressure–volume–temperature (PVT) data showing changes in saturation pressure and CO₂ solubility;

  • Microscopic observations of phase interfaces and asphaltene precipitation under reservoir conditions;

  • Comparative analysis between pure CO₂ flooding and CO₂–additive flooding cases.

Parallel Flooding System for EOR Study

1. Overview

The Parallel Flooding System is a laboratory-scale apparatus designed to simulate and compare multiple Enhanced Oil Recovery (EOR) processes under controlled and reproducible reservoir conditions. It enables simultaneous flooding tests through multiple core samples—typically two or three channels—in parallel, allowing for direct comparison of different injection schemes (e.g., waterflooding, CO₂ flooding, surfactant/polymer flooding, or hybrid processes such as WAG).

This system provides valuable insights into the influence of fluid composition, pressure, temperature, and rock properties on recovery efficiency, capillary number, and residual oil saturation.

2. System Configuration

The Parallel Flooding System consists of the following main components:

  • High-pressure injection pumps:
    Precision metering pumps capable of delivering CO₂, brine, or chemical solutions independently to each core holder at controlled flow rates (typically 0.01–5.0 mL/min) and pressures up to 70 MPa.

  • Core holder assemblies (dual or triple configuration):
    Each core holder is made of stainless steel with a high-temperature heating jacket and a confining pressure sleeve. Confining pressure (up to 80 MPa) simulates reservoir overburden stress, while back-pressure regulators maintain outlet pressure.

  • Temperature control unit:
    A programmable heating system ensures stable and uniform temperature (ambient to 200 °C) for all parallel channels, maintaining consistent thermal conditions for comparative testing.

  • Fluid distribution and collection manifold:
    The system includes precision valves, check valves, and isolation lines to independently control each flooding path. Effluents are directed to separate collection cylinders or fraction collectors for fluid analysis.

  • Online sensors and data acquisition:
    Real-time monitoring of pressure differential, temperature, and injection/production rates for each core. Optional sensors allow optical/NIR/Raman integration for fluid visualization and phase monitoring.

  • Gas–liquid separation and measurement system:
    The produced fluids from each core are separated and measured to determine oil recovery, gas/oil/water ratio, and composition.

3. Experimental Procedure

  1. Core preparation and saturation:
    Each core sample is cleaned, dried, and vacuum-saturated with formation brine, followed by crude oil flooding to establish initial oil saturation (Soi).

  2. Baseline waterflooding:
    Brine is injected simultaneously through each core to measure initial recovery and verify system consistency.

  3. EOR flooding sequence:
    Different injection fluids (e.g., CO₂, polymer solution, surfactant–CO₂ mixture) are applied to each channel in parallel to compare displacement mechanisms.

  4. Production monitoring:
    Differential pressure and produced fluid volumes are continuously recorded for each channel. The cumulative oil recovery and pressure profiles are plotted versus injected pore volume.

  5. Post-flood analysis:
    Produced samples are analyzed for viscosity, CO₂ content, and solid precipitation (wax/asphaltene). Residual oil saturation is determined by solvent extraction or CT imaging.

4. Key Capabilities and Advantages

  • Parallel comparative testing: enables direct evaluation of multiple EOR formulations or injection strategies under identical boundary conditions.

  • High accuracy and reproducibility: identical temperature and pressure control across channels minimizes experimental bias.

  • Customizable flow configurations: supports steady-state, WAG, chemical, or hybrid injection sequences.

  • Optional optical integration: compatible with visual, IR, or Raman high-pressure cells for in-situ phase observation.

  • Scalable and automated: can be integrated with a computer-controlled data acquisition system for unattended operation and reproducible testing.

5. Applications

  • Comparative assessment of CO₂–water–chemical additive EOR systems.

  • Evaluation of surfactant, polymer, nanoparticle, and ionic liquid flooding performance.

  • Study of asphaltene/wax deposition or mobility control mechanisms under reservoir P–T conditions.

  • Calibration of reservoir simulation models based on laboratory-scale flooding data.