Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions.
In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin. In the first phase, we measure baselines for water and kerosene imbibition into the rock samples by conducting spontaneous imbibition tests. In the second phase, we measure expansion of the rock samples during imbibition of water and kerosene, in separate tests, using a linear variable differential transformer (LVDT). In the third phase, we measure imbibition-induced tensile stress during water imbibition into the samples.
The results show that both HRB and DUV shale samples imbibe more water than kerosene, due to water adsorption by clay minerals. Imbibition of water increases the porosity of the HRB and the DUV samples by up to 0.94 and 0.25 percentage points, respectively. Expansion of all samples is anisotropic, with higher expansion perpendicular to the depositional lamination. Water imbibition into the samples induces an expansive stress as high as 17 psi. Moreover, applying confining stress reduces the imbibition of water by up to 18.1% and 33.7% in the HRB and DUV samples, respectively.
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.
This paper presents comprehensive rock-fluid experiments to study the possibility of oil recovery improvement when CO2 is injected as a fracturing fluid in the Montney tight-oil play, located in the Western Canadian Sedimentary Basin. This study consists of four phases: In phase 1, we conduct constant composition expansion (CCE) tests with different CO2 concentrations using a PVT cell. In phase 2, we visualize CO2-oil interactions at reservoir pressure and temperature in a custom-designed visual cell. Then, we conduct SEM/EDS analysis on the solid precipitates in the visual cell due to CO2-oil interactions. In phase 3, we soak the oil-saturated core plugs in the visual cell, pressurize the cell with CO2, and measure the oil recovery. In phase 4, we conduct cyclic CO2 tests using a core flooding system, and measure the oil recovery. We also evaluate the oil viscosity and wettability of the core plugs before and after cyclic CO2 process.
The results of the CCE tests conducted using the PVT cell and visualization tests conducted using the visual cell show that CO2 can significantly dissolve into and expand the Montney oil. The results of the CO2 soaking tests and cyclic CO2 process show that the oil swelling due to CO2-oil interactions results in high oil recovery factor from the oil-saturated core plugs. In addition, we observe solid precipitates due to CO2-oil interactions at the bulk-phase conditions in the visual cell. SEM/EDS analysis on the solid precipitates show the existence of carbon and sulfur, the main components of asphaltene. The results of IP-143 test confirm the formation asphaltene when the Montney oil contacts CO2 at reservoir conditions.
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.
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | He, Jia (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio (Nexen Energy ULC)
As observed in many shale-gas plays, the produced flowback water is highly saline and the salt concentration increases with time. Several past studies investigated water-rock interactions to interpret flowback chemical data, evaluate reservoir performance, and investigate the environmental impacts of fracturing operations. In this study, we measure the total ion produced (
In order to investigate the effect of
Recent studies show that the pore network of unconventional rocks, such as gas shales, generally consists of inorganic and organic parts. The organic part is strongly oil-wet and preferentially imbibes the oleic phase. In contrast, the inorganic part is usually hydrophilic and preferentially imbibes the aqueous phase. Conventional theories of relative permeability, which are based on uniform wettability, cannot be applied to determine phase permeability in unconventional rocks with dual-wettability behavior. The objective of this paper is to extend the previous theories to model relative permeability of dual-wettability systems in which oleic and aqueous phases can both act as wetting phases in hydrophobic and hydrophilic pore networks, respectively.
In the first part of the paper, we review and discuss the results of scanning electron microscopy (SEM), organic petrography, mercury injection capillary pressure (MICP), and comparative water/oil imbibition experiments conducted on several samples from the Triassic Montney tight gas siltstone play of the Western Canadian Sedimentary Basin. We also discuss various crossplots to understand the reasons behind the observed dual-wettability behavior, and to investigate the spatial distribution and morphology of hydrophilic and hydrophobic pores. In the second part, Purcell’s model (Purcell 1949) is extended to develop a conceptual model for relative permeability of gas and water in a dual-wettability system such as the Montney tight gas formation. Finally, the proposed model is compared with measured relative permeability data.
The results suggest that the submicron pores within solid bitumen/pyrobitumen are strongly water-repellant; therefore, they prefer gas over water under different saturation conditions. This part of the pore network is usually represented by a long tail at the lower end of the pore-throat-size distribution determined from MICP. The proposed relative permeability model describes single-phase flow of gas through the tail part, and two-phase flow of gas and water through the remaining bell-shaped part of the pore-throat-size distribution, which dominantly represents inorganic micropores. On the basis of our model, by increasing the fraction of water-repellant submicron pores, gas relative permeability decreases for a fixed water saturation. This decrease is ascribed to the reduction of the average size of flow conduits for the gas phase.
The importance of evaluating well productivity after hydraulic fracturing cannot be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage-fractured wells. Similarly, there have been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters, such as fracture pore volume (PV), half-length, and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture PV independent of fracture geometry. This study starts by use of rate-normalized-pressure (RNP) plots to observe changes in fluid-flow mechanisms from multistage- fractured wells. The fracture “pressure-supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between RNP and time, useful for interpreting flowback data in wells that show pseudosteady-state behavior (unit slope on log-log RNP plots). The linear relationship is implemented on a simple Monte Carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture PV by use of probabilistic distributions of average fracture compressibility and gas/water saturations. Also, the proposed model investigates the contributions of various drive mechanisms during flowback (fracture closure, gas expansion, and water depletion) by use of quantitative drive indices similar to those used in conventional reservoir engineering. Application of the proposed tank model to flowback data from 15 shale-gas and tight-oil wells estimates the effective fracture PV and initial average gas saturation in the active fracture network. The results show that fracture-PV estimation is most sensitive to fracture closure compared with gas expansion and water depletion, making fracture closure the primary drive mechanism during early-flowback periods. Also, the initial average gas saturation for all wells is less than 20%. The parameters estimated from the proposed model could be used as input guides for more-complex studies (such as discrete-fracture-network modeling and transient-flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.
This paper presents comprehensive rock/fluid experiments, by use of reservoir rock and fluids, to investigate wetting affinity of the Montney (MT) tight oil play in the Western Canadian Sedimentary Basin. Wettability characterization is essential for selecting optimum fracturing and treatment fluids by completion engineers and for selecting appropriate relative permeability and capillary pressure curves by reservoir engineers. Application of the conventional techniques for wettability evaluation of tight rocks is challenging primarily because of their extremely low permeability and complex pore structure. The objective of this paper is to develop an alternative laboratory protocol for evaluating the wettability of tight oil rocks reliably. First, we conducted systematic spontaneous-imbibition tests on fresh core samples from two different wells drilled in the MT formation. We measured the air/brine, air/oil, and brine/oil contact angles for all samples. We used the end pieces of the samples to conduct scanning electron microscopy (SEM) and analysis of the elemental mapping, or energy-dispersive X-ray spectroscopy (EDS). Finally, we investigated the spontaneous imbibition of brine (or oil) into the samples partly saturated with oil (or brine). Both oil and brine spontaneously imbibe into the fresh samples, composed of quartz, carbonates (dolomite/calcite), clay minerals, feldspars, and organic matter. The results indicate that the effective pore network exhibits a mixed-wet behavior. Moreover, brine spontaneously imbibes into and forces the oil out of the oil-saturated samples, whereas oil cannot imbibe into the brine-saturated samples. This indicates that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.
Xu, Yanmin (University of Alberta) | Ezulike, Obinna Daniel (University of Alberta) | Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Virues, Claudio (Nexen Energy ULC)
This paper presents an integrated workflow which complementarily utilizes flowback data analysis and surveillance microseismic analysis to characterize fracture networks and stimulated reservoir volume (SRV). The workflow helps to 1) differentiate !"effective" and "ineffective" SRV and fracture half-length (
The application of this workflow on an eight-well pad completed in the Horn River Basin (HRB) shows that the SRV and
In this study, we conduct spontaneous imbibition tests and measure air-oil and air-brine contact angles of nine twin core plugs from five wells drilled in the Duvernay Formation, which is a source rock located in the Western Canadian Sedimentary Basin (WCSB). We investigate the wettability of Duvernay samples with a wide range of porosity (2.0-6.2 %B. V), TOC (2.2-6.6 wt%), kerogen type (III and IV), and kerogen maturity (wet-gas, dry-gas, and over-mature). We characterize the samples by measuring the porosity, permeability, bulk density, matrix density, mineralogy, and rock-eval pyrolysis tests.
We observe a positive correlation between porosity/permeability and the total organic carbon (TOC) content of the samples. The bulk density of the core samples decreases with increasing the TOC content. The relationships of porosity, permeability, and bulk density with TOC indicate that the majority of pores exist in the organic matter of the samples. We define oil wettability index (WIo) based on the equilibrium imbibed volume of oil and brine. The results of spontaneous imbibition experiments show that the samples with higher TOC content and porosity have higher WIo. In addition, we observe negative correlation of WIo with bulk density. We also investigate the correlations of oil wettability index with natural gamma ray (GR) radiation, uranium concentration, and density porosity (φD). The results show that the samples with higher gamma ray, uranium concentration, and density porosity have higher TOC and porosity, and thus higher affinity to oil compared with brine.
Organic-rich shales have been considered as potential reserves across the world (Gonzalez, 2013). Extraction of hydrocarbon from shale rocks in the United States is considered as one of the landmark events in this century (Wang et al., 2014). These unconventional resources with ultra-low permeability can produce hydrocarbon at economic rates from hydraulically fractured horizontal wells. However, successful recovery from such reservoirs requires correct characterization of rock/fluid properties. Wettability affects the electrical properties of rock, capillary pressure, water flood behavior, relative permeability, dispersion, and simulated EOR (Anderson, 1986). Evaluation of shale wettability is significant for 1) mitigating low fracturing fluid recovery after fracturing operations (Cheng, 2012; Ghanbari and Dehghanpour, 2015 and 2016), 2) investigating water blockage in matrix followed by rapid decline in production rate (Bertoncello et al., 2014), 3) selecting the type of fracturing fluid (water-based or oil-based) and its additives (Montgomery, 2013), and 4) investigating the consequences of condensate dropout below dew point pressure (Sheng, 2016; Sheng and Li, 2016; Meng and Sheng, 2016).