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Collaborating Authors
Results
Abstract Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we compare the PSD of shale samples using both of the adsorption and desorption isotherms of water (H2O), nitrogen (N2), and carbon dioxide (CO2). The shale samples are collected from three wells completed in the Horn River Basin. A setup is designed to obtain the water sorption (adsorption and desorption) isotherms for shale samples. The model developed by Zolfaghari and Dehghanpour (2015) is used to calculate the PSD of shale samples from water sorption isotherms. BET (Brunauer-Emmett-Teller) analysis is used to obtain the N2 and CO2 sorption isotherms, and their corresponding PSDs. Also, SEM (Scanning Electron Microscope) images of the shale samples are utilized to visualize the pores of the shale samples. The comparative analysis of PSDs indicates that different methods give different PSDs. All of the calculated PSDs indicate that majority of the pores are smaller than ~10 nm. The portion of pores less than than ~1.5 nm is larger when the PSDs are calculated using the water sorption isotherms compared to that of the BET analysis. The PSDs calculated from the water sorption isotherms also show pores of larger than ~40 nm, which is in agreement with the SEM images of the shale samples. However, BET does not detect these large pores.
- North America > Canada > Alberta (0.68)
- North America > Canada > British Columbia (0.48)
- North America > United States > Texas (0.46)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- (8 more...)
Effect of Electrostatic Interactions on Water Uptake of Gas Shales: The Interplay of Solution Ionic Strength, Electrostatic Double Layer, and Shale Zeta Potential
Binazadeh, Mojtaba (University of Alberta) | Xu, Mingxiang (University of Alberta) | Jiang, Kaiyan (University of Alberta) | Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta)
Abstract The uptake of water by rock matrix in a hydrocarbon producing well brings in both economic justification and environmental concerns. A detailed understanding of the water-rock interactions is essential for design and implication of hydrocarbon recovery techniques and environmental impact analysis. In this study, the water imbibition results are described by the electrostatic interactions between the water and shale samples. The effect of leachable ions in the shale, imbibed fluid ionic strength, electrostatic double layer, and zeta potential of shale are studied. The shale powders are washed with DI (deionized water) sequentially. Individual ion concentrations are obtained by ICP-MS analysis. The ionic strength and Debye length of the brine obtained from each step of the washing experiment are calculated. Zeta potential of the fresh and washed powders are measured in DI water and 10-times concentrated brines from first washing stage (CN brines). A set-up is designed to perform the imbibition experiments on the intact and washed shale powders. DI water and CN brines are used as the imbibing fluids. Washing with DI water leached ions out of the shale powders. After a maximum of 7 washing steps, the ionic strength of the resulting brine solution reached to a constant value which cannot be further reduced by washing. Zeta potential of shale powders in CN brines are substantially lower than the zeta potential of shale powders in DI water. This reduction in the zeta potential value to higher ionic strength of CN brines as compared with DI water. Imbibition experiments reveal that the CN brine solutions imbibe slower into the shale powders as compared with DI water. DI water imbibes faster in washed powders as compared with fresh powders. Debye length is correlated with imbibition rate, as higher Debye length of the solution results in faster imbibition. A reduction in the solution ionic strength increases the thickness of electrostatic double layer and zeta potential value. The thickness of electrostatic double layer in contact with the shale surface, which is modulated by the ionic strength of the in-situ brine solution, is an important factor that influence the particle zeta potential of shale as well as the imbibition rate of aqueous solution into shales.
- North America > United States (1.00)
- North America > Canada > British Columbia (0.46)
- North America > Canada > Alberta (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.98)
- North America > United States > Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.98)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.98)
- (7 more...)
Abstract Petrophysical characterization of unconventional rocks is an important challenge faced by the industry for reservoir evaluation. In particular, characterizing the pore size distribution (PSD) of tight rocks is challenging due to their small pore size and presence of clay minerals. In this paper, we develope a model to characterize PSD of shales using water adsorption isotherms. We apply the model on several shale samples and compare the results with the PSDs obtained from BET (Brunauer-Emmett-Teller) analysis using the N2 and CO2 adsorption isotherms. The proposed model describes the relationship between the cumulative adsorbed water and the size of the invaded pores due to capillary condensation during the water adsorption process. A set-up is designed to obtain water adsorption isotherms. The shale samples are placed in a sealed environment with a controlled relative humidity (RH). Different saturated salt solutions are used to control RH. At the end of the adsorption process, the model is applied to calculate PSD of the shale samples using their water adsorption isotherm. In order to evaluate the model results, we used BET analysis to obtain PSD from the N2 and CO2 adsorption isotherms. Moreover, the specific surface area (SSA), pore volume (PV) and the average pore size of the shale samples are also obtained from the BET analysis to compare the proposed model and BET results. The results of both BET and the proposed model indicate that the majority of the pores are smaller than 10 nm. However, the model results from the water adsorption show a bimodal PSD, while the BET analysis shows a unimodal PSD. Also, the model calculates small pores of less than 1 nm, while BET does not detect these pores. Water adsorption by clay minerals at low RH values is a possible reason for this discrepancy. Furthermore, the sample with higher clay content shows larger hysteresis at the end of the sorption (adsorption-desorption) experiment; suggesting that the clay-bound water cannot be easily removed during the desorption process.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.68)
Advances in Flowback Chemical Analysis of Gas Shales
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | Holyk, Jordan (University of Alberta) | Binazadeh, Mojtaba (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC)
Abstract Recently, flowback chemical analysis has been considered as a complementary approach for evaluating fracturing operations and characterizing reservoir properties. Understanding the source of flowback salts and the mechanisms controlling the water chemistry is essential but also challenging due to the complexity of shale-water interactions. In this study, samples of flowback water and downhole shales are analyzed to investigate the mechanisms controlling the chemistry of flowback water. The water samples at different flowback times and the shale samples are collected from three wells completed in the Muskwa, Otter-Park, and Evie members of the Horn River Basin. The water samples consist of aqueous solution and precipitated salts. The water samples are digested in nitric acid to dissolve the precipitated salts, and are analyzed at both intact and acid-digested conditions using ICP-MS. The flowback salts are weighted and analyzed using XRD and SEM-EDXS. A sequential ion-extraction is performed on the shale samples; and the extracted ions are categorized into three tiers of loosely-, moderately-, and strongly-attached ions. The concentration of monovalent cations in both intact and acid-digested samples is higher than that of divalent cations. Also, the concentration of all cations is higher in the acid-digested samples compared with that in the intact samples. The ratio of divalent cations concentration in the acid-digested samples to that in the intact samples is higher than that for the monovalent cations. This ratio increases for the divalent cations over time, while it remains constant for the monovalent cations. Additionally, for the acid-digested samples the monovalent cations concentration has an initial sharp increase followed by a slower increase at later flowback stages; while the divalent cations concentration increases continuously over time. These results suggest that the majority of the ions in the early flowback water are loosely-attached monovalent ions. These ions can be originated from the mixing with in-situ formation brine, dissolution of soluble precipitated salts, or leaching of exchangeable cations from the clay minerals. Similarly, the role of relatively slow water-rock interactions (such as leaching of divalent exchangeable cations, e.g. Ca,) increases at the later flowback stages. XRD and SEM-EDXS analyzes of the flowback salts indicate that sodium chloride, potassium chloride, and calcium carbonate are the major salts. The sequential ion-extraction reveals that the majority of the monovalent cations are in the loosely-attached tier. However, majority of the divalent cations are moderately- /strongly-attached to the rock. The strongly-attached portion of the ions is determined by acid digestion of the rock sample at the final stage of sequential extraction process. These strongly-attached ions cannot be easily released by hydraulic fracturing and therefore, has small effect on the flowback water chemistry.
- North America > United States > West Virginia (1.00)
- North America > Canada > British Columbia (0.87)
- North America > United States > Pennsylvania (0.68)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)