In this study, we use a custom-designed visual cell to investigate nonequilibrium carbon dioxide (CO2)/oil interactions under high-pressure/high-temperature conditions. We visualize the CO2/oil interface and measure the visual-cell pressure over time. We perform five sets of visualization tests. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with a Montney (MTN) oil sample. In the fourth test, to visualize the interactions in the bulk oil phase, we replace the opaque MTN oil with a translucent Duvernay (DUV) light oil (LO). Finally, we conduct an N2(sc)/oil test to compare the results with those of CO2(sc)/oil test. We also compare the results of nonequilibrium CO2/oil interactions with those obtained from conventional pressure/volume/temperature (PVT) tests.
Results of the first three tests show that oil immediately expands upon injection of CO2 into the visual cell. CO2(sc) leads to the maximum oil expansion followed by CO2(l) and CO2(g). Furthermore, the rate of oil expansion in the CO2(sc)/oil test is higher than that in CO2(l)/oil and CO2(g)/oil tests. We also observe extracting and condensing flows at the CO2(l)/oil and CO2(sc)/oil interfaces. Moreover, we observe density-driven fingers inside the LO phase because of the local increase in the density of LO. The results of PVT tests show that the density of the CO2/oil mixture is higher than that of the CO2-free oil, explaining the density-driven natural convection during CO2(sc) injection into the visual cell. We do not observe either extracting/condensing flows or density-driven mixing for the N2(sc)/oil test, explaining the low expansion of oil in this test. The results suggest that the combination of density-driven natural convection and extracting/condensing flows enhances CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.
In this study, we evaluate the wettability of shale plugs from the Duvernay Formation, which is a self-sourced reservoir in the Western Canadian Sedimentary Basin. We use reservoir oil and flowback water (brine) to conduct air/liquid contact-angle and air/liquid spontaneous-imbibition tests for wettability evaluation. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, and total-organic-carbon (TOC) content, and by conducting rock-eval pyrolysis tests. We also conduct scanning-electron-microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses on the shale samples to characterize the location and size of pores. After evaluation of wettability, we conduct soaking tests. First, we measure liquid/liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on the surface of the oil-saturated plugs. Then, we conduct soaking tests by immersing the oil-saturated plugs in different soaking fluids, and record the oil volume produced from spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension (ST), interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recovery factor (RF).
The results demonstrate that the shale samples have stronger wetting affinity toward oil compared with brine. The positive correlations of TOC content with effective porosity and pressure-decay permeability suggest that the majority of connected pores are within the organic matter. The strong oil-wetness of the shale samples can be explained by the abundance of organic porosity, verified by the SEM/EDS images. The results of liquid/liquid contact-angle tests show that the soaking fluid with lower IFT exhibits a stronger wetting affinity toward the shale. The results also show that oil RF is higher for the soaking fluids with lower IFT, which may be caused by wettability alteration. In addition, comparing the results of air/brine imbibition with those of the soaking tests indicates that adding nonionic surfactant to the soaking fluid may alter the wettability of hydrophobic organic pores toward less-oil-wet conditions, leading to the displacement of oil from organic pores.
Co-injection of CO2 or light hydrocarbons with steam in the SAGD process may improve SAGD efficiency and lead to lower greenhouse gas emissions through reduced Steam Oil Ratios (SORs). Various additives are postulated to have differing effects on bitumen recovery, depending on the nature of the reservoir, the operating conditions, and the API gravity of the oil. A PVT study was conducted to investigate the phase behaviour of CO2-, C3-, and C4-bitumen systems at varying concentrations, representing the edge of a SAP steam chamber with the expected temperature range of 70°C to 160°C.
A produced and dewatered bitumen sample was collected from the Cenovus Osprey Pilot in the Cold Lake oil sands region and characterized. Constant Composition Expansion (CCE) experiments were conducted on solvent-bitumen systems in the temperature range of 70°C to 160°C. Filtration tests were also conducted at high temperature and reservoir pressure to investigate the effect of solvent type and concentration on asphaltene precipitation. A Peng-Robinson Equation of State (PR-EOS) model was calibrated to measured data for CO2-, C3-, and C4-bitumen systems. Viscosity of the bitumen saturated with CO2, C3, and C4 was measured with an electromagnetic-based viscometer elevated temperatures. Phase equilibrium calculations were performed using the calibrated EOS to predict the solubility of the solvents in bitumen. A correlation was fitted to the measured viscosity data to predict the liquid phase viscosity as a function of solvent solubility and temperature for each solvent.
From the CCE tests, two equilibrium phases (i.e., liquid and vapour) were observed for the C3- and CO2-bitumen systems. Three equilibrium phases were observed for the C4-bitumen system at high C4 concentrations. These three phases include a bitumen-rich heavy oil phase, a solvent-rich lighter oil phase, and a vapour phase. Due to the extracting/condensing mechanism and asphaltene precipitation, the bitumen-rich phase formed in C3-bitumen system was lighter than the one in C4-bitumen system. Filtration tests showed more asphaltene precipitation by C3 and C4 dissolution than CO2. Moreover, C3 has more potential for asphaltene precipitation than C4.
Viscosity measurements showed that dissolution of C3 and C4 in bitumen resulted in greater viscosity reduction than CO2 dissolution. This difference was more pronounced at lower temperatures. The highest C4 solubility in bitumen and C4 potential for forming a C4-rich liquid phase showed stronger condensing and extracting effect of C4 than C3 and CO2 in solvent-bitumen interactions. Moreover, C4 lead to more bitumen swelling than C3 and CO2. EOS predictions and viscosity measurements indicated that increasing the solvent concentration in a solvent-bitumen system beyond a defined Threshold Solvent Concentration (TSC) has an insignificant effect on solvent solubility and bitumen viscosity reduction.
Yarveicy, Hamidreza (University of Alberta) | Habibi, Ali (University of Alberta) | Pegov, Serge (University of Alberta) | Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta)
In this paper, we experimentally investigate the possibility of formation damage reduction during leak-off and flowback processes by adding surfactants to the fracturing fluid. The experiments consist of three phases: In phase I, we conduct compatibility tests on surfactant solutions to select the compatible surfactant solutions with saline reservoir brine. In phase II, we measure interfacial tension between the stable surfactant solutions and the Montney reservoir oil. In phase III, we conduct a series of core flooding tests on the Montney tight core plug to experimentally investigate the leak-off and flowback processes. To evaluate the effects of surfactant solutions on the formation damage reduction we 1) measure the pressure drop across the core plug during both leak-off and flowback processes, and 2) evaluate the oil recovery factor during the leak-off process.
The results of the compatibility tests show that the anionic soloterra surfactant solutions with hydrophile-lipophile balance (HLB) numbers higher than 10 are compatible with the saline/reservoir brine. Among all stable soloterra surfactant solutions, the soloterra 983 solution shows the lowest interfacial tension (IFT) values. The results of core flooding experiments indicate that the addition of soloterra 983 surfactant into the saline reservoir brine can reduce the pressure drop during leak-off and flowback processes, and therefore, it decreases the possibility of aqueous phase trapping and formation damage in the Montney tight core plugs.
Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.
In this study, we use a custom-designed visual cell to investigate non-equilibrium CO2/oil interactions under high-pressure and high-temperature conditions. We visualize the CO2/oil interface and measure visual cell's pressure over time. We perform 5 sets of visualization test. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with the Montney oil. In the fourth test, in order to visualize the interactions at the bulk oil phase, we replace the opaque Montney oil with a translucent Duvernay light oil (LO). Finally, we conduct N2(sc)-Oil test to compare the results with those of CO2-Oil tests.
Results of the first three tests show that oil immediately expands upon injection of CO2 into the visual cell. CO2(sc) leads to the maximum oil expansion followed by CO2l and CO2(g). Furthermore, the rate of oil expansion in CO2(sc)-Oil test is higher than that in CO2(l)-Oil and CO2(g)-Oil tests. We also observe extracting and condensing flows at the CO2(l)-Oil and CO2(sc)-Oil interfaces. Moreover, we observe density-driven fingers inside the LO phase due to the local increase in the density of LO. We do not observe neither extracting/condensing flows nor density-driven mixing for N2(sc)-Oil and CO2(g)-Oil tests, explaining low expansion of oil in these tests. The results suggest that the combination of density-driven natural mixing and extracting/condensing flows enhance CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.
Co-injection of CO2 or light hydrocarbons with steam in SAGD (Steam Assisted Gravity Drainage) process may enhance bitumen mobility and reduce Steam Oil Ratio (SOR). Understanding and modeling the phase behavior of solvent-bitumen system 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. Constant composition expansion (CCE) experiments are conducted for characterizing Clearwater bitumen, CO2-bitumen mixture, and C4-bitumen mixture. The Peng-Robinson equation of state (PR-EOS) is calibrated based on the measured data and used for PVT modeling. Multiphase equilibrium calculations are performed to predict the solubility of CO2 and C4 in the temperature range of 120 °C to180 °C. Further to that, dead oil viscosity measurements are conducted at similar temperature intervals to estimate oleic phase viscosity.
According to the CCE tests and multiphase equilibrium calculations, C4 has much higher solubility in bitumen than CO2 at reservoir pressure of 580 psia (4,000 kpa) and temperature range of 120 °C to 180 °C. During the CCE tests, co-existence of three equilibrium phases is observed for the C4-bitumen system with 84 wt.% C4. The three phases consist of a solvent-lean (bitumen-rich) oleic phase (L1), gaseous phase (V) and a solvent-rich (bitumen-lean) oleic phase (L2). Compositional analysis of the samples from L1 and L2 phases shows that C4 can extract light hydrocarbon components from bitumen into L2 phase and preserve the heavy components in L1 phase. It is observed that the color of L2 phase becomes lighter by decreasing the pressure which may suggest extraction of lighter hydrocarbon components at lower pressures. Similar tests on the CO2-bitumen system only shows two effective phases over a similar temperature range. The two phases consist of a solvent-lean (bitumen-rich) oleic phase (L1) and a gaseous phase (V).
By using the regressed EOS model, phase equilibrium regions are predicted in the compositional space for the solvent-bitumen system. EOS predictions indicate two types of two-phase regions in composition space for C4-bitumen system (i.e., L1-L2 in temperature range of 120 °C to 148 °C and L1-V in temperature range of 148 °C to180 °C). However, only one type of two-phase region (i.e., L1-V) exists in the similar temperature range for CO2-bitumen system. The EOS predictions show that 1.7 wt.% CO2 can reduce bitumen viscosity by up to 4 times, and 8.7 wt.% C4 can reduce bitumen viscosity by up to 32 times in temperature range of 120 °C to 180 °C.
This study presents a workflow for identifying and evaluating well interference, and investigating how interference affects fracture cleanup in a multi-well pad.
We analyze flowback pressure and tracer data from a 10-well pad completed in three shale members of the Horn River Basin. Three key steps are used in this study: First, we analyze the tracer concentration profiles to investigate well interference in the pad before flowback. Second, we compare the casing pressure of the wells during selective shut-in and re-opening to investigate well interference during flowback and post-flowback periods. Third, we construct diagnostic plots of gas-water ratio (GWR) to see how well interference affects fracture cleanup during flowback.
We observe that well interference in the pad occurs in three stages – before flowback, during flowback and during post-flowback. Before flowback, concentration profiles from some wells show early breakthrough of tracers injected into neighboring wells in the pad. Analysis of the tracer data suggests that fracturing operations create connecting pathways among the wells in the pad. During flowback and post-flowback, we observe that the shut-in and re-opening of some wells in the pad disturb the recorded pressure in the remaining wells. The log-log plots of GWR versus cumulative gas production for late-opened wells show an approximate half-slope, suggesting fracture cleanup. However, this trend of fracture cleanup is not observed for the early-opened wells. This shows that the early-opened wells drain fracturing water from the late-opened wells through connected fractures, when the wells in a pad are opened for flowback in a sequence. Combined analysis of flowback and tracer data helps to understand how fracturing water migrates between wells, and to optimize well placement in a pad.
“Frac-hit” is a common phenomenon when multi-fractured horizontal wells are tightly spaced in an unconventional reservoir. Frac-hit is a rapid pressure increase in wells that are shut-in during the fracturing treatment of offset wells. Well interference during fracturing operations has been identified and evaluated using the pressure increase during frac-hit (Sardinha et al. 2014; Lehmann et al. 2016). However, it is not clear if the well interference caused by frac-hit is sustained after fracturing treatment, and how it affects hydrocarbon production.
Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated samples in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the recovery data of the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition on dry samples suggest that the affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and counter-current imbibition tests suggest that the affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil. Finally, we introduce a porosity-based model to analyze oil-recovery data.
In this study, we evaluate the wettability of shale samples drilled in the Duvernay Formation, which is a source-rock reservoir located in the Western Canadian Sedimentary Basin (WCSB). We use reservoir oil and brine to conduct air-liquid contact angle and air-liquid spontaneous imbibition tests for wettability measurements. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. We also conduct Scanning Electron Microscope (SEM) and energy-dispersive x-ray spectroscopy (EDS) analyses on the shale samples to characterize the location and size of pores. After evaluation of wettability, we conduct soaking experiments. First, we measure liquid-liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on surface of the rock samples. Then, we immerse the oil-saturated samples in the soaking fluids with different compositions and physical properties. The we record the oil volume produced due to spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension, interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recover factor (RF).
The results of wettability measurements demonstrate that the shale samples have stronger wetting affinity to oil compared with brine. The positive correlations of TOC content with effective porosity and pressure-decay permeability suggest that the majority of connected pores are present within the organic matter. Organic porosity may explain the strong oil-wetness of the shale samples. The SEM/EDS analyses also show the abundance of organic nanopores within organic matter. The results of liquid-liquid contact angle tests show that a reduction in IFT of the soaking fluid leads to an increase in wetting affinity of rock to soaking fluid. The results also show that oil RF is higher for soaking fluids with lower IFT, which can be explained by wettability alteration. The shale samples have higher wetting affinity to soaking fluids with lower IFT, leading to an increase in the driving capillary pressure and, consequently to higher oil recovery by spontaneous imbibition. In addition, comparing the results of air-brine imbibition with soaking tests suggests that adding surfactant to the soaking fluid may alter the wettability of organic pores towards more water-wetness, leading to the displacement of oil from hydrophobic organic pores.