Dehghanpour Lab

Non-equilibrium CO2-Oil Interactions

We utilize the visualization cell to investigate the interactions between carbon dioxide (CO2) and oil under HPHT conditions. We visualize the CO2/oil interface and measure the pressure within the cell over time. We conduct a series of tests to explore how gaseous, liquid, and supercritical CO2 interacts with Montney and Duvernay oil samples. Our findings reveal that upon injecting CO2 into the visual cell, the oil immediately expands. Specifically, supercritical CO2 results in the greatest oil expansion, followed by liquid and gaseous CO2. Additionally, the rate of oil expansion is highest during the supercritical CO2/oil test as compared to the CO2(l)/oil and CO2(g)/oil tests.

Further observations show that extracting and condensing flows occurred at both the CO2(l)/oil and CO2(sc)/oil interfaces. We also note density-driven fingers within the liquid oil phase due to the local increase in oil density. These results indicate that the combination of density-driven natural convection and extracting/condensing flows enhances CO2(sc) dissolution into the oil phase, ultimately leading to rapid oil expansion after CO2(sc) injection into the visual cell.

Visualization of Natural Gas and Oil Interactions under HPHT Conditions

Accurate phase behavior and volumetric data are essential to accurately simulate oil recovery processes during enhanced oil recovery (EOR) operations under downhole conditions. Swelling tests and minimum miscibility pressure (MMP) measurements from pressure-volume-temperature (PVT) experiments are typically used to understand the equilibrium gas-oil interactions during gas injection operations. However, relatively short gas injection processes may not reach equilibrium conditions, and non-equilibrium gas-oil interactions can occur.

To visually study such interactions, our research group has developed a custom-designed visualization cell for high-pressure and high-temperature (HPHT) experiments. Our experiments involve different gases, including methane, ethane, propane, carbon dioxide, and nitrogen and oil samples from unconventional formations such as Eagle Ford, Montney, and Duvernay. We conduct bulk-phase experiments under the same conditions as gas HnP processes but without rock samples. This method allows for the observation of non-equilibrium gas-oil interactions, which can provide insights into the performance of EOR operations.

Laboratory Simulation of Natural Gas HnP on Tight Rock Samples

Gas Huff-n-Puff is an enhanced oil recovery (EOR) technique in unconventional reservoirs which is becoming a common practice over the last decades. This single-well EOR technique involves injecting gas into the wellbore during the “huff” stage, shutting in the well for a period to allow for gas and oil interactions during the “soaking” stage, and finally reopening the same well for oil production during the “puff” stage.

Dr. Hassan's research group has conducted extensive studies on the feasibility and optimization of the gas huff-n-puff process in various unconventional formations, including Montney, Duvernay, and Eagle Ford. To simulate the process in a laboratory scale, the team has designed and built a cutting-edge visualization cell capable of conducting high-pressure and high-temperature (HPHT) gas huff-n-puff experiments under representative reservoir conditions.

The unique design of the visualization cell allows researchers to perform experiments using a wide range of gas compositions, including hydrocarbon and non-hydrocarbon gases. Real-time monitoring of gas-oil interactions during the experiment is facilitated through the built-in sight glasses, which provides valuable insights into the efficiency of the EOR technique.

Natural Gas HnP in Montney Formation

We conduct a series of systematic gas HnP experiments on ultratight core plugs from the Montney tight-oil formation, under reservoir conditions (P = 137.9 bar and T = 50°C), to study the mechanisms controlling gas transport and oil recovery. We inject natural-gas mixtures (C1 and a mixture of C1/C2 with a molar ratio of 70:30) into the plug, followed by soaking and depressurization phases. We use the custom-designed visualization cell to observe the gas transport and oil recovery mechanisms.

Our observations indicate that advective-dominated transport is the primary mechanism responsible for the transport of gas into the plug during the early stages of the soaking period, followed by molecular diffusion at the later stages of soaking. Our results demonstrate that gas expansion is the dominant mechanism for oil recovery, followed by total system compressibility, oil swelling, and vaporization. Furthermore, enriching the injected gas with 30-mol% C2 significantly improved gas transport into the plug and increased oil recovery compared to pure C1 cases.

Chemical EOR while fracturing: the protocols to screen chemical additives

Our research group proposed laboratory protocols to screen chemical additives such as surfactants and nanoparticles for enhanced oil recovery (EOR) from tight rocks with ultralow permeability and porosity. We characterize different parameters that may affect the performance of chemical additives on wettability alteration and oil recovery enhancement, and investigate the interactions between rock, fluid and additives during the extended shut-in period.

The laboratory workflow can help the operators to design and screen optimum chemical additives for enhancing well productivity after the fracturing operations. The results can lead to an advanced understanding of additives-oil-rock interactions, the formation of precipitations, suspensions and adsorptions in fracturing fluids under harsh conditions.

Bitumen Recovery for from Oil-sand Resources by Cyclic Solvent Injection

Common bitumen recovery processes, such as SAGD (Steam-Assisted Gravity Drainage) and VAPEX (Vapor Extraction), are not suitable for thin reservoirs due to the heavy consumption of water and heat, and the lack of a gravity drainage mechanism, respectively. As an alternative, Cyclic Solvent Injection (CSI) at low temperatures has been developed as a more sustainable and energy-efficient technique for bitumen recovery from oil-sand reservoirs. Our ongoing experiments aim to conduct specific CSI experiments to see how does the propane phase affect bitumen recovery? and what mechanisms control bitumen recovery at different propane phases?

In Dr. Dehghanpour’s research lab, we synthesized core plugs from in-situ oil-sand and bitumen samples of the Clearwater Formation at Cold Lake. Different CSI experiments are already conducted by liquid propane (C3,L), two-phase propane (C3,V-L), and vapor propane (C3,V) in a state-of-the-art visualization cell, equipped with a camera and a digital pressure transducer. We analyze the pressure profiles and images from the core face during the CSI experiments. Our results show that bitumen recovery by C3,V is higher than that by C3,L. Besides, we observed that when CSI is conducted by C3,L, the core face is plugged by asphaltene deposition. Furthermore, in CSI by C3,L, the limited bitumen recovery occurs when pressure is dropped below the saturation pressure of propane during depletion. The results also suggest that the combination of asphaltene deposition, solution gas drive, oil extraction and production under wormhole support are the mechanisms controlling bitumen recovery from the oil-sand cores.

Visualizing the Interactions Between Liquid Propane and Heavy Oil

We utilize a custom-designed visualization cell to investigate the non-equilibrium interactions between liquid propane (C3,l) and heavy oil from Clearwater Formation under varying experimental conditions. We inject C3,l into the visual cell during the pressure-buildup process, allowing the injected C3,l to interact with the heavy oil sample in a soaking process. During this stage, we measure the pressure inside the visual cell and monitor the interactions between C3,l and heavy oil. We also record the non-equilibrium interactions occurring at the interfaces of C3,l /heavy oil and C3,l/C3,v (vapor propane) over time.

Based on our observations, the complete mixing of heavy oil with C3,l occurs in two stages. Initially, during the soaking process, upward extracting flows of oil components from the bulk heavy oil phase towards the C3,l phase forms a distinguishable layer (L1). Over time, the extracted oil components become denser and move downward towards the C3,l/heavy oil interface due to the gravity (draining flows). The gradual color change of L1 from colorless (color of pure C3,l) to black suggests the mixing of oil components with C3,l. Extracting and draining flows lead to the mixing of oil components, forming a single uniform phase.