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Keywords: Hydrogen Storage; Unconventional Reservoirs; Enhanced Oil Recove
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Visualizing Oil Recovery Mechanisms During Natural Gas Huff-n-Puff Experiments on Ultra-tight Core Plugs Low oil recovery factors and rapid decline rates are key challenges in developing shale and tight oil formations. Despite encouraging gas Huff-n-Puff (HnP) field pilot results, the oil-recovery mechanisms are still not well understood. This paper investigates the oil-recovery mechanisms during a natural gas (C1 and a mixture of C1/C2 with the molar ratio of 70/30) HnP process on ultralow-permeability Montney plugs. This study comprises of two sets of tests that are conducted under core-plug and bulk-phase conditions. To investigate oil-recovery mechanisms from an oil-saturated core plug, we used a custom-designed visualization cell to visualize the interactions at the surface of the plug during natural-gas injection (huff), soaking, and pressure-depletion (puff) processes under reservoir conditions of 2,000 psig and 50oC. This experimental setup simulates a 1-D gas diffusion process which is believed to occur at the fracture faces during the gas HnP process. To complement the core-plug tests, we conducted bulk-phase tests including (1) vanishing interfacial tension (VIT) to estimate minimum miscibility pressure (MMP), (2) constant composition expansion (CCE), and (3) visualization tests to study the phase behavior of gas-oil systems.
We observed four main oil-recovery mechanisms including vaporizing/condensing-gas drive, oil swelling, molecular diffusion, and solution-gas drive, from the core-plug and bulk-phase tests. In that, the major mechanisms are the oil swelling, molecular diffusion, and solution-gas drive during the injection, soaking and depressurization phases of the core-soaking tests, respectively. Oil swelling in C1 and C1/C2 tests appears to be pronounced during gas-injection and soaking phases. During the depressurization phase, the expansion of diffused gas leads to a significant flow of oil comingled with gas, observed at the surface of the plug. According to the MMP measurements, increasing mol% of C2 in the injection gas (0 to 29.7%) reduces MMP of the gas-oil system from 4,350 psig to 2,726 psig. The developed miscibility conditions by enrichment of injection gas enhance the diffusivity of gas into the oil phase and the plug during the soaking period. Vaporization of oil components into the gas phase and condensation of C1/C2 into the oil phase in the bulk-phase visualization tests lead to higher oil swelling in the C1/C2 test compared to pure C1 test. The results of CCE and bulk-phase visualization tests suggest that the addition of C2 to the injection gas increases oil swelling which may explain higher oil recovery by the C1/C2 mixture compared with pure C1 in the core-soaking tests.
T07-P05 University of Alberta Publication 2020-06-10 T07-P05 Pore Size Distribution of Unconventional Rocks with Dual-Wet Pore Network: A Sequential Spontaneous and Forced Imbibition Technique Recent wettability studies indicate the dual-wet behavior of unconventional rocks that have hydrophobic
pores within the organic matter with low wetting affinity to brine. In contrast, the hydrophilic pores bordered
by inorganic minerals such as quartz, feldspar, calcite, and clays have strong wetting affinity to brine.
The total pore network composed of hydrophobic and hydrophilic pores exhibits a dual-wet behavior.
Conventional methods such as mercury injection capillary pressure (MICP) and nitrogen/CO2 sorption
tests give the total pore size distribution (PSDtot), regardless of pore wettability. Modeling two- phase
transport mechanisms in such dual-wet media requires separate characterization of hydrophobic (PSDHB)
and hydrophilic (PSDHL) pore size distributions.
We proposed a two-step experimental procedure for estimating PSDHB and PSDHL. In Step 1, we used
reservoir brine and conducted co-current spontaneous imbibition (SI) tests on dry shale plugs from the
Duvernay Formation. We considered the pore network of shale plugs as an idealized bundle of tortuous
capillary tubes, and estimated PSDHL using imbibition transient analysis (ITA) proposed in a previous
study. The Lucas-Washburn equation was combined with a fractal model to develop ITA. In Step 2, we
immersed partly brine-saturated plugs from SI test (Step 1) in brine and increased the pressure incrementally
(forced imbibition or drainage process). We used incremental brine saturation at each pressure and estimated
PSDHB by the Young-Laplace (Y-L) equation. The results show that cumulative pore space filled by brine
in spontaneous- and forced-imbibition tests under maximum pressure of 9,500 psig is more that 90% of
pore volume (PV), while mercury in MICP test can fill less than 40% of PV under maximum pressure of
55,110 psig. Therefore, pore size distribution estimated by brine-imbibition tests is expected to be more
representative compared with that estimated by MICP tests. The peak-pore throat size of hydrophobic
pores (Dpeak-HB) estimated by forced imbibition of brine is in the range of 5.8-14.6 nm, consistent with
the two-dimensional visualization of organic pores using scanning electron microscopy (SEM) analysis.
The minimum values of pore-throat diameters detected in mercury- and brine-injection tests are 3.8 nm
and 1.2 nm, respectively. Therefore, smaller pore throats can be characterized by brine-injection test at a
significantly lower pressure (9,500 psig) compared with that by mercury-injection test (55,110 psig). The results show that a part of the pore network with pore throats smaller than 3.8 nm is not accessible for
mercury. However, brine can be injected into this part of the pore network.T07-P05 University of Alberta Publication 2019-11-29 T07-P05 Wettability Of Calcareous Shales From The East Duvernay Basin: The Role Of Natural Fractures, Thermal Maturity, And Organic-Pore Connectivity In this study, we conducted rock/fluid experiments to investigate wettability of calcareous shale plugs from a well drilled in the early oil-window (EOW) of East Duvernay. The wettability of EOW plugs was compared with that of highly-mature and quartz-rich plugs in the oil and gas windows (OGW) of the Duvernay Formation to investigate the effects of kerogen maturity and mineralogy on pore morphology and wettability of shales. We investigated the effects of organic-pore connectivity and fractures on wettability of the EOW plugs. By using CT scan images, we divided EOW plugs into highly-fractured (HF), slightly-fractured (SF), and non-fractured (NF) plugs. We used reservoir oil and brine and conducted comparative imbibition tests on the core plugs to investigate effects of fracture intensity on imbibition profiles. The core plugs were characterized by analyzing the results of tight-rock analysis (TRA), x-ray diffraction (XRD), and rock-eval pyrolysis.
Compared with the quartz-rich OGW plugs, the EOW plugs are categorized as calcite-rich shale (calcareous shale) with high average calcite content of 60%. The EOW plugs are rich in organic matter (average total organic carbon (TOC) of 7.3 wt%) with significantly high value of Hydrogen Index (HI > 500). Surprisingly, the results of wettability tests show higher normalized imbibed volume of brine compared with that of oil, suggesting that the EOW plugs are preferentially water-wet. This trend is opposite to what we previously observed for the oil-wet OGW plugs with significantly high organic porosity, positively correlated to TOC content. We did not observe well-developed organic pores within organic matter of less-mature EOW plugs. We also observed that the normalized imbibed volume of oil is much higher in the HF and SF plugs compared with that in the NF plugs. The results suggest that the fractures enhance accessibility of isolated pores, leading to more connected pore network for oil imbibition. This observation suggests that fracture porosity plays a significant role in wetting behavior of the EOW plugs. The results show that the porosity measured by Boyle’s law helium-porosimetry using crushed EOW samples is significantly higher than their effective porosity. This is because crushing the samples enhances accessibility of isolated pores considered as ineffective porosity under intact conditions. Combined analyses of imbibition profiles and core images of the fractured plugs show that oil rapidly imbibes into the fracture system, and then gradually imbibes from fractures into rock matrix.
T07-P05 University of Alberta Publication 2020-02-14 T07-P05 Annual consortium meeting for unconventional petroleum production This is an annual workshop organized by our research group to showcase the results of research projects carried out throughout the year. The participants are from the Civil and Environmental Engineering Department and industry collaborators. The event was scheduled for May, however, due to the pandemic situation, we decided to move it to a virtual platform on July 23. T07-P05 University of Alberta Activity 2020-07-23 Dehghanpour, H. , Mahmood Reza Yassin, Son Thai Tran, Mohammad Hossein Doranehgard
T07-P05 Visualizing Interactions Between Liquid Propane and Heavy Oil In this study, we use a custom-designed visual cell to investigate nonequilibrium interactions between liquid propane (C3(l)) and a heavy oil sample (7.2 oAPI) at varying experimental conditions. We inject C3(l) into the visual cell containing the heavy oil sample (pressure-buildup process) and allow the injected C3(l) to interact with the oil sample (soaking process). We measure visual-cell pressure and visualize the C3/heavy oil interactions during the pressure-buildup and soaking processes. Nonequilibrium interactions occurring at the interfaces of C3(l)/heavy oil and C3(l)/C3(g) are recorded with respect to time.
The results show that complete mixing of heavy oil with C3(l) occurs in two stages. First, upward extracting flows of oil components from bulk heavy oil phase toward C3(l) phase form a distinguished layer (L1) during the soaking process. The extracted oil components become denser over time and move downward (draining flows) toward the C3(l)/heavy oil interface due to gravity. The gradual color change of L1 from colorless (color of pure C3(l)) to black suggests the mixing of oil components with C3(l). After L1 appears to be uniform, a second layer (L2) is formed above L1 in the bulk C3(l) phase. Extracting and draining flows become active once again, leading to mixing of oil components from L1 into L2. At final conditions, heavy oil and C3(l) appear to be mixed and form a single uniform phase.T07-P05 University of Alberta Publication 2020-06-18 T07-P05 Quantifying Oil-Recovery Mechanisms during Natural-Gas Huff ‘n’ Puff Experiments on Ultratight Core Plugs Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70/30) HnP experiments on an ultratight core plug collected from the Montney tight-oil Formation, under reservoir conditions (P = 137.9 bar and T = 50oC). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling (i) gas transport into the plug during injection and soaking phases, and (ii) oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (∆Pi = Pg−Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number (NPe) analysis to quantify the contribution of each transport mechanism during the soaking period.
We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe = 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ∆Pi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the ‘puff’ period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30 mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.T07-P05 University of Alberta Publication 2020-10-05 Son Thai Tran, Mahmood Reza Yassin, Sara Eghbali, Mohammad Hossein Doranehgard,
Dehghanpour, H. T07-P05 Quantifying Oil-Recovery Mechanisms during Natural-Gas Huff ‘n’ Puff Experiments on Ultratight Core Plugs Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1, C1/C2 - 70/30 mol%) HnP experiments on an ultratight Montney core plug under reservoir conditions. We used a custom-designed visualization cell to evaluate mechanisms controlling (i) gas transport into the plug, and (ii) oil recovery during the whole process. We also perform a Péclet number (NPe) analysis to quantify gas-transport mechanisms during the soaking period.
We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe = 1.58 to 3.03), while molecular diffusion dominates at the late times (NPe = 0.26 to 0.62). From the four studied recovery mechanisms, gas expansion is the dominant one, followed by total system compressibility, oil swelling, and vaporization. The enrichment of injected gas by C2 enhances the transport of gas into the plug and increases oil recovery.T07-P05 University of Alberta Activity 2020-11-24 Son Thai Tran, Mahmood Reza Yassin, Mohammad Hossein Doranehgard, Sara Eghbali,
Dehghanpour, H. T07-P05 The effects of kerogen maturity on pore structure and wettability of organic-rich calcareous shales Organic-rich shales are considered important unconventional resources nowadays. The primary objective of this research is to evaluate the hydrocarbon potential in calcareous shale plugs by investigating their wettability and pore structure. We conducted spontaneous imbibition (SI) tests on calcareous shale plugs with low maturity level from 5 wells drilled in the early-oil and oil windows in East Shale Basin (ESB) of the Duvernay Formation. We compared the SI results with those of highly-mature and quartz-rich plugs in the oil and gas windows in the West Shale Basin (WSB) of the Duvernay Formation as well as their petrophysical properties. We investigated the relationships between kerogen maturity and rock mineralogy on SI results and pore structure of organic-rich shales by analyzing SEM images and low-pressure gas sorption (LPGS) test results. The ESB plugs are categorized as calcareous shales that are rich in organic matter (average total organic carbon (TOC) of 5.5 wt%). The results of SI tests show that ESB plugs are preferentially water-wet with exceptions in plugs with higher kerogen maturity. The oil wettability index (WIo) of ESB plugs is positively correlated with production index (PI) and Tmax, but not with TOC content. The LPGS test results show that micro and fine mesopores within organic matter (OM) are more abundant in plugs with higher kerogen maturity. The lack of well-developed organic pores within OM of the early-mature ESB plugs is also confirmed with SEM images. Our results suggested that ESB plugs with low maturity level in early-oil window have low oil potentials despite their TOC-rich characteristics. One may use this finding for selecting sweet spots for shale oil production by evaluating kerogen maturity level of the organic deposits.
T07-P05 University of Alberta Publication 2022-09-01 T07-P05 Unconventional well shut-in and reopening: Multiphase gas-oil interactions and their consequences on well performance Recent field reports show the uplift in oil production rate (qo), after the shut-in period, referred to as “flush production”. The conventional hypotheses for explaining this phenomenon are based on water-oil-rock interactions such as counter-current oil production and water-blockage reduction due to imbibition of fracturing water. Here, we hypothesize other drive mechanisms responsible for the uplift in qo: 1) pressure buildup near matrix-fracture interface during the shut-in period, 2) increasing oil saturation (So) and compressibility (co) due to an increase in solution-gas content at higher pressures, and 3) gas expansion (solution-gas drive) during pressure drawdown after restarting the well. We analyzed the production data of two unconventional wells which were shut-in for 194 and 20 days after the primary-production period. Analysis of production data indicates that pressure buildup is the primary mechanism responsible for higher post-shut-in qo, followed by an increase in oil relative permeability (kro). The results of our compositional simulations show that by increasing the pressure near the fracture face during the shut-in period, a fraction of the free gas is dissolved in the oil phase, leading to an increase in So which is considered as the primary factor for kro enhancement. Increasing co because of increasing solution-gas content is the secondary factor that improves post-shut-in kro. However, gas relative permeability (krg) drops after the shut-in period while kroincreases. The reduction of gas saturation because of pressure buildup during the shut-in period and trapping of the gas phase due to hysteresis effect are the two reasons that explain krg reduction.
T07-P05 University of Alberta Publication 2022-08-01 T07-P05 An experimental and field case study to evaluate the effects of shut-in on well performance There is still debate on how shutting fractured wells for a period of time can affect the well performance. In this study, we combined two approaches to better understand the effects of shut-in time on well performance. First, we analyzed flowback and post-flowback production data from a horizontal well drilled in the Montney Formation, which was fractured with water containing a microemulsion (ME) additive. After the shut-in time for 7 months, the oil and solution gas rates significantly increased by 750% and 671%, respectively. However, the free gas rate decreased by 95% in 65 days, before it started to build up again to exceed the values at the start of the production. Second, we performed a series of imbibition oil-recovery, dynamic liquid-liquid contact angle, and interfacial tension measurements to investigate how the interplay of (i) capillary suction and (ii) osmotic pressure affects oil production from core plugs during the counter-current imbibition tests. Combined analyses of field and laboratory results suggest that the increase in oil production rate after the shut-in period is due to combined effects of (i) free-gas dissolution into the oil (ii) capillary imbibition of fracturing water containing ME solution into the rock matrix driven by wettability alteration and osmotic pressure, and (iii) reduction in phase trapping near fracture face due to interfacial tension reduction.
T07-P05 University of Alberta Publication 2022-01-01 Taregh Soleiman Asl, Ali Habibi, Mahmood Reza Yassin, Obinna Daniel Ezulike,
Dehghanpour, H. T07-P05 Evaluating Formation Damage and Remediation Methods: Physical Simulation of Leak-Off and Flowback This paper aims at investigating the change in oil effective permeability due to fracturing fluid leak-off after hydraulic fracturing of tight carbonate reservoirs. We perform a series of flooding tests on core
plugs with a wide range of porosity and permeability collected from the Midale tight carbonate Formation
to simulate fracturing fluid leak-off and flowback processes. First, we clean and saturate the plugs with
reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P=2500 psig
and T=60 deg C). Then, we measure oil effective permeability before (baseline) and after the leak-off process to evaluate the effects of (i) fracturing fluid properties, (ii) shut-in duration, and (iii) core properties on regained permeability values.
We found that adding proper surfactants in fracturing fluid not only significantly reduces oil effective permeability
impairment due to leak-off, but also improves oil effective permeability compared with the original baseline for low-permeability carbonate cores. For a plug with relatively high permeability, freshwater leak-off reduced oil effective permeability by 55% (from 1.57 mD to 0.7 mD) while fracturing fluid (with surfactants) reduced by only
oil effective permeability by 10%. The observed improvement in is primarily due to the reduction of interfacial tension (IFT) by
the surfactants (from 26.07 mN/m to 5.79 mN/m). The contact-angle measurements before and after the
flowback process do not show any significant wettability alteration. The results show that for the highpermeability
plugs, fracturing fluid leak-off reduces oil effective permeability by 5-10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the low-permeability plug, the regained
permeability is even higher than the original oil effective permeability before the leak-off process. We observed 29% and 65% increase in oil effective permeability after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug which
significantly reduces irreducible water saturation (Swirr), and consequently increases oil effective permeability. In such situations, extending the shut-in time enhances the mixing between invaded fracturing fluid and oil/brine
initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results
show that the regained permeability strongly depends on permeability, pore structure, and Swirr of the
plugs.T07-P05 University of Alberta Publication 2020-02-03 T07-P05 Leakoff and Flowback Experiments on Tight Carbonate Core Plugs This paper aims at investigating the change in oil effective permeability due to fracturing fluid leak-off after hydraulic fracturing of tight carbonate reservoirs. We perform a series of flooding tests on core
plugs with a wide range of porosity and permeability collected from the Midale tight carbonate Formation
to simulate fracturing fluid leak-off and flowback processes. First, we clean and saturate the plugs with
reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P=2500 psig
and T=60 deg C). Then, we measure oil effective permeability before (baseline) and after the leak-off process to evaluate the effects of (i) fracturing fluid properties, (ii) shut-in duration, and (iii) core properties on regained permeability values.
We found that adding proper surfactants in fracturing fluid not only significantly reduces oil effective permeability
impairment due to leak-off, but also improves oil effective permeability compared with the original baseline for low-permeability carbonate cores. For a plug with relatively high permeability, freshwater leak-off reduced oil effective permeability by 55% (from 1.57 mD to 0.7 mD) while fracturing fluid (with surfactants) reduced by only
oil effective permeability by 10%. The observed improvement in oil effective permeability is primarily due to the reduction of interfacial tension (IFT) by the surfactants (from 26.07 mN/m to 5.79 mN/m). The contact-angle measurements before and after the flowback process do not show any significant wettability alteration. The results show that for the highpermeability
plugs, fracturing fluid leak-off reduces oil effective permeability by 5-10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the low-permeability plug, the regained
permeability is even higher than the original oil effective permeability before the leak-off process. We observed 29% and 65% increase in oil effective permeability after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug which
significantly reduces irreducible water saturation (Swirr), and consequently increases oil effective permeability. In such situations, extending the shut-in time enhances the mixing between invaded fracturing fluid and oil/brine
initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results
show that the regained permeability strongly depends on permeability, pore structure, and Swirr of the
plugs.T07-P05 University of Alberta Publication 2021-03-17 T07-P05 Studying Phase Behavior of Oil-Natural Gas Systems for Designing Gas Injection Operations: A Montney Case Study Advances in horizontal drilling and multistage hydraulic fracturing have unlocked tight oil formations, such as Montney in Western Canadian Sedimentary Basin. However, the average oil recovery factor after primary production is 5-10 % of the original oil in place. The aim of this study is to investigate phase behavior and estimate minimum miscibility pressure (MMP) of Montney oil-natural gas systems. The gas samples used in this study are methane (C1) and mixtures of methane/ethane (C1/C2).
To achieve these objectives, we first measure the MMP of the oil-gas system using vanishing interfacial tension (VIT) technique. Second, we perform constant composition expansion (CCE) tests to study the phase behavior of the oil-gas systems using a pressure-volume-temperature cell. Finally, we use the measured CCE data to calibrate Peng-Robinson equation of state (EOS) and estimate MMPs for the oil-gas systems using ternary diagrams.
The results suggest that mechanism for developing miscibility conditions in the system of oil-C1 is vaporizing gas drive, while it is a condensing gas drive for the oil-C1/C2 system. According to the results of VIT tests, adding and increasing C2 mol% in the gas mixtures lead to a significant reduction of MMP of the oil-gas mixture (from 4366 psi for oil-C1 to 1467 psi for oil-C1/C2 with 71.3 mol% C2). The addition and increase of C2 mol% in the gas mixtures enhance oil swelling (a maximum swelling factor of 1.76 for oil-C2 mixture) and reduce MMP of the oil-gas system. Reasonable PR-EOS models are developed from the CCE data and shown thermodynamic reliability to predict fluid phase behavior within the reservoir. The predicted MMPs by plotting two-phase equilibrium data on ternary diagrams appear to be in good agreement with the measured ones. The MMP of the oil-C1/C2 systems can be achieved by either increasing injection pressure or the mole fraction of C2.
T07-P05 University of Alberta Publication 2019-11-18 T07-P05 Leak-Off and Flowback Experiments on Tight Carbonate Core Plugs This paper aims at investigating the change in oil effective permeability (ko_eff) due to fracturing fluid leak-off in the Midale tight carbonate reservoir. We perform coreflood tests to measure ko_eff before (baseline) and after the leak-off process to evaluate the effects of (i) fracturing fluid properties, (ii) shut-in duration, and (iii) plug properties on regained permeability values. We found that adding proper surfactants in fracturing fluid not only significantly reduces ko_eff impairment due to leak-off (55% to about 10% in plugs with kair>0.13 mD), but also improves ko_eff compared with the baseline for a low-permeability carbonate plug (kair<0.09 mD). In the plug with tight pore network, extending the shut-in time enhances the mixing between invaded fracturing fluid and oil/brine initially in the plug, leading to more effective reductions of interfacial tension and irreducible water saturation.T07-P05 University of Alberta Activity 2020-05-05 T07-P05 Modeling of Natural-Gas Diffusion in Oil-Saturated Tight Porous Media In this paper, we propose a novel analytical solution to predict the diffusion coefficient and depth of natural gas penetration during the soaking period of the cyclic gas injection process.
Our analytical solution is derived from the modeling of gas-phase pressure declines by the use of mass balance and continuity equations. We model mass transport during the soaking period as a counter diffusion process, and find that diffusion coefficient and velocity are controlled by the pressure gradient at the early soaking times and the gas concentration gradient when the soaking progresses. We calculate the depth of gas penetration in the plug and show that during the soaking period oil production rate ∝ √T07-P05 University of Alberta Publication 2021-04-23 T07-P05 Evaluation of Enhanced Oil Recovery Application in Tight-Oil Formations PhD Dissertation of Son Tran:
The rapid decline rates and low oil recovery factor (typically less than 10% of the original oil in place) of primary production are well-known challenges in the development of tight-oil formations. Several enhanced-oil-recovery studies and field trials have been conducted with promising results in these formations, however, key oil-recovery mechanisms are poorly understood. This research evaluates mechanisms controlling oil recovery during a natural-gas huff ‘n’ puff (HnP) and fracturing-fluid (FF) leakoff/flowback processes in tight-oil formations.T07-P05 Publication 2021-05-10 Son Thai Tran
T07-P05 Estimating compressibility of complex fracture networks in unconventional reservoirs Previous studies show that fracture closure is the primary drive mechanism for fracture cleanup during flowback process in hydraulically stimulated reservoirs.
Estimating fracture compressibility is practically essential to calculate effective fracture volume, evaluate fracture volume change, and forecast ultimate hydrocarbon
recovery. However, limited experimental data are available for evaluating compressibility of fracture networks in unconventional reservoirs. In this paper, we
categorize induced fractures into unpropped and propped fractures, and estimate their compressibilities from fracture conductivity measurements and Hertzian contact
theory, respectively. We also investigate the effects of rock and proppant parameters on fracture compressibility. Finally, we propose a workflow to estimate
compressibility of complex fracture networks and investigate the roles of propped and unpropped fractures during fracture closure. The results show that fracture
compressibility depends on how fracture porosity and aperture change with effective stress. For propped fractures, the rate of porosity change primarily controls fracture
compressibility. In addition, compressibility of complex fracture networks approximates that of unpropped fractures at low effective stress and that of propped
fractures at high effective stress. Overall, the results highlight the role of unpropped fractures in hydrocarbon recovery from stimulated unconventional reservoirs.T07-P05 University of Alberta Publication 2020-02-04 T07-P05 Measuring diffusion coefficients of gaseous propane in heavy oil at elevated temperatures Molecular diffusion is an important phenomenon for solvent transport during vapor extraction and hot solvent injection into heavy oil reservoirs. Therefore, determining solvent diffusion into heavy oil is important for predicting oil recovery. We conduct soaking tests at different temperatures ranging from 80 to 130 °C to estimate diffusion coefficient of propane (C3H8) into heavy oil samples taken from Clearwater Formation in the Western Canadian Sedimentary Basin. The tests are conducted at the maximum initial pressure of 1900 kPa to keep C3 in vapor phase within the tests’ temperature range. Pressure decline during the soaking process is analyzed to estimate diffusion coefficients and solubility of propane in the oil at equilibrium conditions. The final viscosity of the mixture is also calculated by using the available correlations. The results show that diffusion of propane in heavy oil undergoes three different stages: early region, transition region, and late-time region. The maximum diffusion coefficient is observed at the end of transition region. Solubility of C3 in the oil increases with decreasing temperature. The results also reveal that during the three regions, solubility and diffusion coefficients of C3 into the oil strongly depend on temperature.T07-P05 University of Alberta Publication 2020-02-03 T07-P05 Quantification of convective and diffusive transport during CO2 dissolution in oil: A numerical and analytical study In this paper, we numerically investigate CO2 dissolution in the liquids. For accurate simulation and capturing instabilities during CO2 dissolution in liquids, we apply interpolation supplemented lattice Boltzmann method (ISLBM).
Using ISLBM, we study the effects of Rayleigh number on the density-driven fingers, introduced the convection field and the amount of dissolved CO2. Our results show that Ra~106 is a threshold value at which the dominant phenomenon changes from diffusive to the convective transport. In fact, at Ra<106, only molecular diffusion (no fingers) can be observed. On the other hand, for Ra≥106, forming vigorous (initial) fingers leads to produce convective transport. According to the obtained result, these initial fingers noticeably affect the concentration variance and mixing rate curves. We observe that mass transfer strongly depends on the Rayleigh number in the way by increasing Ra, the concentration front of CO2 reaches to the bottom earlier and the amount of dissolved CO2 significantly increases. In addition, it is found that for Ra>106 and after a specific time, the spatial average velocity reaches to a plateau. Outcomes indicate a linear trend between Ra and the advanced finger position.
T07-P05 University of Alberta Publication 2020-08-21 T07-P05 Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions into Tight Plugs Various chemical additives have been recently proposed to enhance imbibition oil recovery from tight formations during the shut-in periods after hydraulic fracturing operations. Although, soaking experiments under laboratory conditions usually confirm the performance of such additives, their effects on oil regained permeability during the flowback process are poorly understood. This is mainly because measuring effective permeability of such low-permeability rocks is extremely challenging. We develop and apply a laboratory protocol mimicking leak-off, shut-in, and flowback processes to evaluate the effects of fracturing fluid additives on oil regained permeability. We modify the conventional coreflooding apparatus to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Adjusting the system total compressibility allows quickly achieving steady-state conditions at multiple ultra-low flowrates. We apply the proposed technique on two tight plugs with and without initial water saturation (Swi), and observe pressure humps during the flowback process that can be explained mathematically using the fractional-flow theory. Spontaneous imbibition of the surfactant solution into the two oil-saturated plugs results in recovery of around 20% of the initial oil. For the plug with Swi = 0, koeff is reduced from around 3 µD to 1 µD, indicating the adverse effect of water trapping over the favorable effects of interfacial tension reduction and wettability alteration by the surfactant. For the plug with Swi = 0.21, koeff increases from 0.85 µD to 1.08 µD that can be explained by the combined effects of Swi reduction and wettability alteration, favorably shifting the oil relative permeability curve.
T07-P05 University of Alberta Publication 2020-10-01 T07-P05 The Effects of Asphaltene Precipitation on Bitumen Recovery during Non-Thermal Cyclic Solvent Injection in Cold Lake Oil Sands-An Experimental Study The non-thermal solvent-based processes for bitumen extraction consume less energy and water, and thus, have less impacts on the environment compared with the steam-based thermal processes. The objective of this paper is to investigate the mechanisms responsible for propane transport into and bitumen production from oil-sand core samples during the cyclic solvent injection (CSI). We use a state-of-the-art high-pressure and high-temperature (HPHT) visualization cell to investigate non-equilibrium propane-bitumen interactions during CSI. We inject propane into the cell containing a bitumen-saturated core plug representing in-situ reservoir conditions. Three sets of tests with different propane vapor (C3(v)) to liquid (C3(l)) ratio are conducted (set 1 with C3(l), set 2 with C3(l)-C3(v) mixture, and set 3 with C3(v)). After the CSI tests, the final bitumen recovery factor is calculated by the weight-balance method and the precipitated asphaltene content caused by propane-bitumen interactions is also measured using a distillation apparatus. When the core is fully immersed in C3(l), the cell pressure rapidly declines during the early soaking process, and then, it declines gradually. However, no obvious pressure decline can be observed when C3(v) is present in the system. This can be explained by the higher compressibility of C3(v) compared to C3(l), leading to a less significant pressure decline during the soaking period. A light hydrocarbon phase is produced from the core at the end of the depletion process, indicating the extraction of light components of oil by propane even at low-temperature conditions. The bitumen recovery factor is the lowest (11.93%) in set 1 when the core is soaked in C3(l), while that is the highest (14.73%) in set 3 when the core is soaked in C3(v). Also, the bitumen production stops quickly at the early soaking period in set 1. This is because asphaltene precipitation is more significant when the C3(l) is present in the system. The propane density in liquid state is higher than that in vapor state, leading to more bitumen-propane interactions and more asphaltene precipitation. The precipitated asphaltene blocks the pore network and inhibits bitumen production. Our results show that increasing C3(v) to C3(v) ratio decreases the amount of asphaltene precipitation, and in turn, increases bitumen recovery factor.
T07-P05 University of Alberta Activity 2022-03-11 T07-P05 Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions into Tight Plugs Various chemical additives have been recently proposed to enhance imbibition oil recovery from tight formations during the shut-in periods after hydraulic fracturing operations. Although, soaking experiments under laboratory conditions usually confirm the performance of such additives, their effects on oil regained permeability during the flowback process are poorly understood. This is mainly because measuring effective permeability of such low-permeability rocks is extremely challenging. We develop and apply a laboratory protocol mimicking leak-off, shut-in, and flowback processes to evaluate the effects of fracturing fluid additives on oil regained permeability. We modify the conventional coreflooding apparatus to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Adjusting the system total compressibility allows quickly achieving steady-state conditions at multiple ultra-low flowrates. We apply the proposed technique on two tight plugs with and without initial water saturation (Swi), and observe pressure humps during the flowback process that can be explained mathematically using the fractional-flow theory. Spontaneous imbibition of the surfactant solution into the two oil-saturated plugs results in recovery of around 20% of the initial oil. For the plug with Swi = 0, koeff is reduced from around 3 µD to 1 µD, indicating the adverse effect of water trapping over the favorable effects of interfacial tension reduction and wettability alteration by the surfactant. For the plug with Swi = 0.21, koeff increases from 0.85 µD to 1.08 µD that can be explained by the combined effects of Swi reduction and wettability alteration, favorably shifting the oil relative permeability curve.
T07-P05 University of Alberta Activity 2022-07-18 T07-P05 A Model and Measurement Technique for Liquid Permeability of Tight Porous Media Based on the Steady-State Method T07-P05 University of Alberta Publication 2022-06-01 T07-P05 Modeling Two-Phase Flow in Tight Core Plugs with an Application for Relative Permeability Measurement T07-P05 University of Alberta Publication 2023-03-01 T07-P05 Evaluating porous media wettability from changes in Helmholtz free energy using spontaneous imbibition profiles Spontaneous imbibition profiles are widely used for wettability evaluation of porous media such as rocks. However, mostly the equilibrium imbibed volume is the basis for wettability evaluation. Here, we model the relationship between the shape of imbibition profile and wettability of a medium. We develop a wettability evaluation criterion based on the change in Helmholtz free energy of the system during the imbibition process. The model relates the Helmholtz free energy to the area under the profile, the slope of the imbibition profile, equilibrium imbibed volume, and equilibrium time. We propose a modified form of Lucas-Washburn equation to model the capillary-driven flow of a viscous wetting phase into a porous medium saturated with a viscous non-wetting phase. We introduce a wettability index using the volume-normalized Helmholtz free energy. Finally, the model is tested on imbibition data of eight twin rock samples, and the wettability results show moderate to strong correlations with rock properties. The results show that wettability indices predicted by the proposed technique exhibit more accurate correlations compared with those obtained by the volume-based method.
T07-P05 University of Alberta Publication 2021-11-01 T07-P05 A Laboratory Protocol to Investigate EOR by Surfactants During Pre-Loading of Parent Wells to Mitigate Fracture Hit T07-P05 University of Alberta Publication 2023-03-01 T07-P05 Experimental and Mathematical Investigation of Natural Gas Huff-n-Puff on Eagle Ford Shale Samples T07-P05 University of Alberta Publication 2023-03-01 T07-P05 GeoConvention Awards - Best Student Presentation T07-P05 Award 2024-06-20 Amin Alinejad
T07-P05 Quantifying Solvent Transport in Fractured Shale Rocks during Soaking Stage of Huff’n’Puff Process T07-P05 Publication 2026-04-30 Amin Alinejad
T07-P05 Effect of Operating Parameters on Solution-Gas Drive and Foamy Oil Flow during Cyclic Solvent Injection: An Experimental and Modeling Study T07-P05 Publication 2026-04-01 Saman Mohammadi, Amin Alinejad
T07-P05 CO2 Huff-n-Puff and Storage in Vaca Muerta Shale T07-P05 Publication 2025-04-25 Amin Alinejad
T07-P05 Effects of Electro-Oxidation Process on Tight-Rock Wettability and Imbibition Oil Recovery Oil and gas industry has faced significant operational, economic, and environmental challenges in recycling produced water. The treatment of produced water is highly researched, but few studies have evaluated the performance of treated produced water when used for hydraulic fracturing and enhanced oil recovery (EOR) operations. In this study, we treated various aqueous solutions, including synthetic formation brine (FB), sodium chloride (NaCl), calcium chloride (CaCl2), and sodium sulfate (Na2SO4), using an electro-oxidation (EO) process. The brine properties, including density, surface tension (ST), oil–water interfacial tension (IFT), viscosity, and pH, were compared before and after the treatment. Then, we conducted systematic contact-angle (CA) measurements and spontaneous imbibition tests using treated and untreated brine to study the effects of water treatment on rock–fluid interactions and its impact on oil recovery. The experimental results show that the effect of the EO process on ST, density, viscosity, and IFT was insignificant. However, the CA results show that the treated FB, NaCl, and Na2SO4 solutions exhibit stronger wetting characteristics compared with the untreated ones, while the treated CaCl2 solution exhibit weaker wetting characteristics compared with the untreated ones. We hypothesized that the change in the wetting characteristics was due to the generated oxidants from the EO process. We added OH–, H+, hydrogen peroxide (H2O2), and sodium hypochlorite (NaOCl) into untreated brine to test this hypothesis and monitored the CA variations. The results suggest that H2O2 and OH– can alter the wettability to more water-wet conditions in the NaCl solution but not in the CaCl2 solution. Furthermore, NaOCl results in wettability alteration to more oil-wet conditions in NaCl and CaCl2 solutions. The change in wettability to more water-wet conditions is mainly the result of the oxidation of dissolved organic matters, and the change to more oil-wet conditions is the result of the dissolution of high-valence cations, causing the cation bridging effect.
T07-P05 University of Alberta Publication 2022-06-01 T07-P05 Application of Electro-oxidation Technology for Water Treatment and Rock Wettability Alteration The unconventional oil and gas industry has been facing numerous operational, economic, and environmental challenges for treating produced water. Although much research has been conducted on improving the treatment of produced water, few studies evaluated the performance of treated produced water when it is reused for fracturing and EOR. In this paper, we treated sodium chloride (NaCl) solution using an electro-oxidation (EO) treatment process and evaluated how the treatment changes brine properties and how the wetting characteristics change with treated brine. The brine properties, including density, surface tension (ST), oil-water interfacial tension (IFT), viscosity, and pH values were measured and compared before and after the treatment. Then, we conducted systematic contact-angle measurements using treated and untreated brine to study the effects of water treatment on rock-fluid interactions. The results show that the EO process slightly reduces ST, density, and viscosity, and slightly increases the pH value. Also, we observed that the IFT between oil and treated brine is slightly lower than that between oil and untreated brine. However, the contact-angle results show that the treated brine provides stronger wetting characteristics than the untreated one. We hypothesized that the change in wetting characteristics is mainly due to the generated oxidants and hydroxide (OH-) from the EO process. To further investigate the mechanisms behind the change in wetting characteristics after treatment, we investigated the diffusion of OH-, H+, hydrogen peroxide (H2O2), and Sodium hypochlorite (NaOCl) into untreated brine and monitored the contact-angle variations. The results suggest that H2O2 and OH- are responsible for the stronger brine wetting characteristics, and NaOCl and H+ are responsible for the stronger oil wetting characteristics. We also found that the EO process produces a significant amount of active chlorine. However, the stability of active chlorine is low, and it can evaporate as chlorine gas. Based on the results, we concluded that the oil-saturated rock samples in treated brine generally have a higher wetting affinity to water than those in untreated brine, and H2O2 and OH- are the main substances that cause the wettability alteration to more water-wet conditions.
T07-P05 University of Alberta Publication 2021-01-01 T07-P05 Liquid imbibition in tight rocks: The role of disjoining pressure Modelling wettability of tight rocks is challenging due to their complex pore networks, sub-micron pore throats, and organic pores. The experimental results show oil-wet behavior of dry core plugs. Assuming different flow paths for oil and water imbibition, the ratio between oil and brine capillary pressure calculated using imbibition profiles is from 0.67 to 1.76, while that calculated by Young-Laplace model is around 0.5. The higher oil imbibition cannot be completely explained by the conventional Young-Laplace model. Therefore, we apply Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory to evaluate intermolecular forces among oil, water, and rock surface by calculating disjoining pressure (Πd). For liquid imbibition in dry samples, the Πd calculations show that the attraction between rock and oil is stronger than that between rock and water, explaining the higher oil imbibition into the core samples. The ratio between oil and brine capillary pressure calculated by the augmented Young-Laplace equation, which considers Πd, is closer to that calculated using the imbibition data. The excess oil imbibition is also due to hydrocarbon coating on inorganic pores and different flow paths for oil and water. The attraction between rock and oil increases if we consider more percentage of pores coated by residual hydrocarbon. To explain the water imbibition into oil-saturated core plugs, we evaluate the stability of the oil and water films covering the rock surface. The calculated Πd profiles suggest that quartz is more water-wet compared with other minerals. The thin water film covering quartz becomes more stable as the film thickness increases, helping oil production from oil-saturated pores composed of quartz. We also calculate Πd for brine with different salinities. Generally, for a rock surface-water-oil system, Πd increases by decreasing water salinity, suggesting more stable water film.
T07-P05 University of Alberta Publication 2021-10-01 T07-P05 A Theoretical Explanation for Wettability Alteration by Adding Nanoparticles in Oil-Water-Tight Rock Systems We evaluated the idea of adding nanoparticles in an aqueous phase to enhance its wetting affinity to siltstone core plugs by conducting dynamic contact-angle experiments and by calculating the total interaction energy. We analyzed the performance of a colloidal dispersion with highly surface-modified silicon dioxide nanoparticles (NP). The rock samples are oil-wet when they are initially aged in the reservoir brine, and they are water-wet when initially soaked in the NP solutions (limiting conditions). To mimic the downhole conditions when the pumped fluid with nanoparticles is mixed with reservoir brine, we measured the change in contact angle of oil droplets initially equilibrated on the rock surface soaked in the reservoir brine during diffusion of the introduced nanoparticles. The results show that the diffusion of nanoparticles through the brine toward the oil droplet alters the system wettability from oil-wet to water-wet conditions. To investigate the mechanisms responsible for the observed wettability alteration, we analyzed aqueous-film stability using the Derjaguin, Landau, Verwey, and Overbeek theory. The calculated interaction energy for the cases of NP solutions is higher than that for the tap water and brine cases, indicating stronger repulsion between the rock and oil across the film of NP solution, leading to a more stable film. Increasing water salinity reduces the stability of water film due to the reduction of total interaction energy. The wettability alteration by the NP solution is more pronounced in the presence of low-salinity water.
T07-P05 University of Alberta Publication 2021-04-01 T07-P05 Application of Electro-oxidation Technology for Water Treatment and Rock Wettability Alteration The unconventional oil and gas industry has been facing numerous operational, economic, and environmental challenges for treating produced water. Although much research has been conducted on improving the treatment of produced water, few studies evaluated the performance of treated produced water when it is reused for fracturing and EOR. In this paper, we treated sodium chloride (NaCl) solution using an electro-oxidation (EO) treatment process and evaluated how the treatment changes brine properties and how the wetting characteristics change with treated brine. The brine properties, including density, surface tension (ST), oil-water interfacial tension (IFT), viscosity, and pH values were measured and compared before and after the treatment. Then, we conducted systematic contact-angle measurements using treated and untreated brine to study the effects of water treatment on rock-fluid interactions. The results show that the EO process slightly reduces ST, density, and viscosity, and slightly increases the pH value. Also, we observed that the IFT between oil and treated brine is slightly lower than that between oil and untreated brine. However, the contact-angle results show that the treated brine provides stronger wetting characteristics than the untreated one. We hypothesized that the change in wetting characteristics is mainly due to the generated oxidants and hydroxide (OH-) from the EO process. To further investigate the mechanisms behind the change in wetting characteristics after treatment, we investigated the diffusion of OH-, H+, hydrogen peroxide (H2O2), and Sodium hypochlorite (NaOCl) into untreated brine and monitored the contact-angle variations. The results suggest that H2O2 and OH- are responsible for the stronger brine wetting characteristics, and NaOCl and H+ are responsible for the stronger oil wetting characteristics. We also found that the EO process produces a significant amount of active chlorine. However, the stability of active chlorine is low, and it can evaporate as chlorine gas. Based on the results, we concluded that the oil-saturated rock samples in treated brine generally have a higher wetting affinity to water than those in untreated brine, and H2O2 and OH- are the main substances that cause the wettability alteration to more water-wet conditions.
T07-P05 University of Alberta Activity 2021-12-01 T07-P05 The investigation of Hydrogen Storage in Salt Caverns T02-A01 Publication 2025-04-01 Lin Yuan
T02-A01 Evaluating Fluid/Rock Interactions for Energy Storage in Salt Caverns–Part II: Effect of Hydrogen on Salt Rock Dissolution in Brine T02-A01 Publication 2025-01-30 Lin Yuan, Adel Najafimarghmaleki
T02-A01 Technical risk evaluation of underground hydrogen storage in Lotsberg Salt Formation: Insights from microscopic evaluations T02-A01 Publication 2025-07-15 Davood Zivar, Lin Yuan
T02-A01 Measuring hydrogen permeability of salt rock for applications in energy storage T02-A01 Publication 2024-09-20 Lin Yuan, Adel Najafimarghmaleki
T02-A01 Measurement of helium diffusion in Lotsberg Salt cores: A proxy to evaluate hydrogen diffusion T02-A01 University of Alberta Publication 2025-01-04 T02-A01 Assessing the Potential of Lotsberg Salt Formation for Cavern Containment and Hydrogen Storage: A Petrophysical Evaluation via Helium Diffusion Measurement T02-A01 Activity 2023-12-15 Lin Yuan
T02-A01 Hydrogen Permeability of Salt Rock under Cavern Operating Conditions–A Lotsberg Case Study T02-A01 Activity 2024-12-15 Lin Yuan
T02-A01 Subsurface Energy Storage workshop We organized this workshop at UofA.T02-A01 Activity 2025-04-21 Lin Yuan, Adel Najafimarghmaleki
T02-A01 GeoConvention Awards - Best Student Presentation T02-A01 Award 2025-06-20 Davood Zivar, Lin Yuan
T02-A01 Surfactant-Induced Wettability Shifts Across Salinity Gradients T07-P05 Publication 2026-04-21 Lin Yuan
T07-P05 Investigating the effects of flow regime on hydrogen transport in salt rock T02-A01 Publication 2025-12-01 Lin Yuan
T02-A01 Permeability of Salt-Rock Samples: Insights into Hydrogen Transport T02-A01 Publication 2025-11-03 Lin Yuan, Adel Najafimarghmaleki
T02-A01 Propane−Bitumen Interactions during Cyclic Solvent Injection―A 2 Cold Lake Case Study Thesis not defended yet (as of May 2023)T07-P05 Publication 2023-07-25 Saman Mohammadi
T07-P05 Evaluating Fluid/Rock Interactions for Energy Storage in Salt Caverns: Part I: Brine–Rock Salt Interactions T02-A01 Publication 2024-10-22 Adel Najafimarghmaleki
T02-A01 Development and Application of a Method for Evaluating Hydrogen Permeability and Porosity of Salt Rocks T02-A01 Publication 2025-07-09 Adel Najafimarghmaleki
T02-A01 An Experimental and Modeling Study of Carbon Dioxide/Bitumen and C4/Bitumen Phase Behavior at Elevated Temperatures Using Cold Lake Bitumen The coinjection of carbon dioxide (CO2) or light hydrocarbons with steam in the steam-assisted-gravity-drainage (SAGD) process
might enhance bitumen mobility and reduce the steam/oil ratio (SOR). Understanding and modeling the phase behavior of solvent/
bitumen systems are essential for the development of in-situ processes for bitumen recovery. In this paper, an experimental and
modeling study is undertaken to characterize the phase behavior of bitumen/CO2 and bitumen/C4 systems. Produced and dewatered oil
from the Cenovus Osprey Pilot is used for the experiments. The Osprey Pilot produces oil from the Clearwater Formation. Constantcomposition-
expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2/bitumen mixture, and C4/bitumen
mixture. The Peng and Robinson (1978) equation of state (EOS) (PR-EOS) is calibrated using the measured data and is used for pressure/
volume/temperature (PVT) modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the
temperature range of 393.2 to 453.2 K. The potential of asphaltene precipitation for CO2/bitumen and C4/bitumen mixtures is also
investigated using three screening criteria.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than does CO2 at operating
pressure of 3997.9 kPa and temperature between 393.2 and 453.2 K. (393.2 K Publication 2019-04-18 T07-P05 An Experimental and Modeling Study on Interactions of Cold Lake Bitumen with CO2, C3, and C4 at High Temperatures Coinjecting CO2 and light hydrocarbons with steam into oil sand reservoirs can improve the efficiency of the
SAGD (steam assisted gravity drainage) process by reducing the steam oil ratio (SOR). The effects of these solvents on bitumen
recovery enhancement depend on reservoir properties and operating conditions. To investigate the effects of solvents on
bitumen viscosity in a solvent aided process, phase behaviors and viscosities of CO2−, C3−, and C4−bitumen systems were
measured and modeled at high temperatures. Using the calibrated Peng−Robinson equation of state (PR-EOS), the solubilities
of solvents in the Clearwater bitumen sample from the Cold Lake region were predicted. High-pressure and high-temperature
equipment using an electromagnetic-based viscometer was customized to measure the viscosities of CO2−, C3−, and C4−
bitumen mixtures. The measured viscosity data were used to calibrate a nonlinear viscosity model which was used to predict
liquid phase viscosity as a function of solvent solubility and temperature. The effects of solvent dissolution on bitumen viscosity
were investigated using PR-EOS and the calibrated viscosity model. The results show that dissolving CO2, C3, and C4 in
bitumen decreases its viscosity. This viscosity reduction is lowest and highest in the case of CO2 and C4 dissolution,
respectively. The effect of solvent dissolution on viscosity reduction is more pronounced at lower temperatures. EOS
predictions and viscosity measurements indicate that increasing concentration of CO2, C3, and C4 above a certain threshold has
a limited effect on reducing bitumen viscosity. At threshold solvent concentrations, bitumen viscosity can be reduced by 1.7, 5.6,
and 15.2 times using CO2, C3, and C4, respectively, at 120 °C. Solubility and viscosity data suggest that C4 has the potential to
be used in hot-solvent recovery methods in shallow and deep oil sand reservoirs. C3 may be a more effective solvent in deeper
reservoirs which allow higher operating pressures. The modified viscosity model showed better performance than the Lobe and
Shu correlations and logarithmic mixing rule. This model improves existing correlations for predicting viscosities of light
solvent−bitumen mixtures since it requires less input data and does not require density data.T07-P05 University of Alberta Publication 2019-04-18 T07-P05 Society of Petroleum Engineer (SPE) - Distinguished Lecturer During the last decade, low-permeability reservoirs have been rapidly developed by horizontal drilling and multi-stage hydraulic fracturing. In particular, tight oil production has pushed the U.S. crude supply to around 10 % of the total world total production. However, only 5-10 % of the original oil in place can be recovered after expensive fracturing operations. Field results suggest that rock-fluid interactions during extended shut-in periods can significantly influence well performance, depending on rock wettability, reservoir conditions, and fracturing water formulation. The lessons learned from such interactions can help the industry to design efficient EOR (enhanced oil recovery) operations.
The first part this lecture interprets the results of the petrophysical analysis, wettability evaluation, and oil-recovery tests conducted on preserved core plugs from several North American shale formations. The core plugs were selected from zones with different maturity levels to cover a wide range of wettability from strongly water-wet to strongly oil-wet. The results show that shale wettability strongly depends on mineralogy, pore structure, rock fabric, organic content, and maturity level. Combined analyses of oil-recovery, wettability and SEM (Scanning Electron Microscopy) results demonstrate that the non-recovered oil is mainly trapped in small oil-wet pores.
The second part of the lecture shows how oil recovery can be significantly enhanced by soaking the core plugs 1) in surfactant solutions altering rock wettability and 2) in supercritical CO2 which can diffuse into and swell the oil in small organic pores. The results suggest that adding proper surfactants in fracturing water or soaking the fractured wells with supercritical CO2 can lead to more efficient wells.
T07-P05 University of Alberta Activity 2020-06-24 T07-P05 Associate Editor, Journal of Petroleum Science and Engineering Associate Editor for the Journal of Petroleum Science and Engineering (ELSEVIER) since 2015.T07-P05 University of Alberta Activity 2020-02-14 T07-P05 Executive committee of SPE Canada virtual unconventional resources conference 2020 Executive Committee of SPE Canada Unconventional Resources Conference 2020. The SPE Canada Unconventional Resources and Heavy Oil Conferences will virtually be held 28 September – 2 October 2020.T07-P05 University of Alberta Activity 2020-07-14 T07-P05 Mid-Career Research Award The Faculty of Engineering Mid-Career Research Award is for mid-career tenured or tenure-track professors. Current University of Alberta Engineering tenured or tenure-track faculty, within 9 years of their doctoral defense (as of the application deadline date), are eligible. Medical, maternity or parental leave is not counted as part of the 9-year period. One award is selected yearly. Criteria are research excellence demonstrated while a faculty member in the Faculty of Engineering. Impact and achievement should be commensurate with stage of career. Without constraining how the case for excellence may be made, quality and impact should be emphasized over quantity.T07-P05 University of Alberta Award 2021-01-04 T07-P05 A Laboratory Workflow to Screen Microemulsion Additives for Hydrocarbon Recovery from Tight Resources We present a comprehensive laboratory workflow to investigate different parameters affecting the efficiency of enhancing oil recovery from tight rocks. We used tight core samples and nanodroplet (ND) solutions prepared by three complex nanofluid (CnF) additives which include nonionic surfactants and solvents to conduct our experiments. This protocol is applied in the following steps: (1) Characterizing natural wettability of the core plugs by spontaneous imbibition and contact angle tests; (2) Evaluating NDassisted imbibition oil recovery tests under different brine salinities; and (3) Performing bulk-phase tests to evaluate fluid properties, particle size, and stability of the ND samples and understand fluid-fluid interactions. The experimental results show that the use of CnF additives decreases the oil-water interfacial tension (IFT) and alters the rock wettability towards more water-wet conditions. However, enhanced imbibition oil recovery using ND solutions prepared by CnF additives cannot be sufficiently explained by IFT reduction and macroscopic CA measurements. Generally, increasing fluid salinity reduces oil recovery by the ND solutions, which can be explained by the weaker osmosis potential and the formation of larger particles in high-salinity water. The solubility results indicate that the formation of middle-phase (or near middle-phase) microemulsion is favorable to increase oil recovery.T07-P05 University of Alberta Publication 2022-10-01 T07-P05 $ 1 million project on hydrogen storage: Investigation and Optimization of Large-scale Hydrogen Storage in Lotsberg Formation Dehghanpour and his team have received $500,000 from Alberta Innovates’ Hydrogen Centre of Excellence to explore the underground hydrogen storage, with at least another $500,000 from industry partners, the Natural Sciences and Engineering Research Council and the Mitacs Accelerate Grants Program.T07-P05 University of Alberta Award 2023-05-05 T07-P05 Half million project on hydrogen storage: Feasibility study, comparative analysis, and optimization of natural gas Huff-n-Puff processes in Duvernay and Eagle Ford formations Dehghanpour and his team have received $500,000 from Alberta Innovates, Natural Sciences and Engineering Research Council and the industry partners to work on natural gas Huff-n-Puff processes.
T07-P05 University of Alberta Award 2023-12-01 T07-P05 The ASTech Award for Hydrogen Innovation T02-A01 University of Alberta Award 2024-11-29 T02-A01 Emerging Leader Award- Canadian Hydrogen Convention (Honorary Mention) T02-A01 University of Alberta Award 2024-09-01 T02-A01 Hydrogen Panel with UofA Leadership at the 2025 Canadian Hydrogen Convention T02-A01 University of Alberta Award 2025-04-21 T02-A01 Co-lead, Center for Hydrogen Innovation, Workforce Development & Outreach, University of Alberta T02-A01 University of Alberta Award 2025-04-01 T02-A01 Interview and filming for the Hydrogen Innovation Center T02-A01 University of Alberta Activity 2025-04-11 T02-A01
