Knapp, Levi J. (Japan Oil, Gas and Metals National Corporation (JOGMEC)) | Nanjo, Takashi (Japan Oil, Gas and Metals National Corporation (JOGMEC)) | Uchida, Shinnosuke (Japan Oil, Gas and Metals National Corporation (JOGMEC)) | Haeri-Ardakani, Omid (Geological Survey of Canada) | Sanei, Hamed (Aarhus University)
This paper was selected for presentation by a JFES program committee following review of an abstract submitted by the author(s). The complexities of these relationships are not well defined however and may be influenced by a variety of factors including organic matter richness, thermal maturity, kerogen type, original kerogen structure and primary organic-hosted porosity, compositional fractionation, interaction with mineral catalysts, compaction, and occlusion by generated products such as solid bitumen. This abstract presents preliminary results from the first of three wells analyzed in the play fairway of the Duvernay Formation of western Canada - a prolific source rock and rising star as an unconventional reservoir. Distinct porosity morphology groups have been observed in SEM and ongoing work has shown that organic matter porosity morphology may be influenced by organic matter composition and degree of isolation from nearby macerals. Integration of porosity calculated from image analysis of focused ion beam scanning electron microscopy (FIB-SEM) images with results from nuclear magnetic resonance (NMR), mercury injection capillary pressure (MICP), and helium porosimetry has demonstrated that a significant portion of the porosity is below typical SEM imaging resolution and that even methods such as He-porosimetry are challenged to access nanometer-scale pores. Variations in sample preparation and analysis procedures can significantly alter porosity results.
Kurz, Bethany A. (Energy & Environmental Research Center) | Sorensen, James A. (Energy & Environmental Research Center) | Hawthorne, Steven B. (Energy & Environmental Research Center) | Smith, Steven (Energy & Environmental Research Center) | Sanei, Hamed (Aarhus University) | Ardakani, Omid (Geological Survey of Canada) | Walls, Joel D. (Ingrain - Halliburton) | Jin, Lu (Energy & Environmental Research Center) | Butler, Shane (Energy & Environmental Research Center) | Beddoe, Christopher (Energy & Environmental Research Center) | Mibeck, Blaise (Energy & Environmental Research Center)
Kerogen is functionally defined as the portion of OM in a sample that is insoluble using organic solvents (Tissot and Welte, 1984). Primary kerogen consists of OM deposited in the sedimentary basins from which hydrocarbons form during the catagenesis process in the sedimentary rocks (Vandenbroucke and Largeau, 2007). Depending on the depositional environment of the rock, kerogens can be composed of algae, spores, pollen, and woody or herbaceous material (Tissot and Welte, 1984). Solid bitumen is also an important component of kerogen in organic-rich mudrocks (Sanei and others, 2015). Solid bitumen is generally defined as a secondary kerogen formed because of cracking of retained hydrocarbon (Jacob, 1984; Curiale, 1986, Sanei and others, 2015). Curiale (1986) also identified a preoil bitumen formed from the earlygeneration (immature) products of rich source rocks, probably extruded as very viscous fluids, which migrated minimal distances to fractures. Some components of solid bitumen, depending on their composition, are generally considered extractable using organic solvents, although at later stages of thermal maturity, solid bitumen becomes a carbon-rich, unextractable solid referred to as pyrobitumen (Jacob, 1984; Curiale, 1986; Sanei and others, 2015).
Akihisa, Kunio (Japan Oil, Gas and Metals National Corporation) | Knapp, Levi (Japan Oil, Gas and Metals National Corporation) | Uchida, Shinnosuke (Japan Oil, Gas and Metals National Corporation) | Shimokawara, Mai (Japan Oil, Gas and Metals National Corporation) | Akita, Yasuyuki (Japan Oil, Gas and Metals National Corporation) | Wood, James M. (Encana Corporation) | Ardakani, Omid Haeri (Natural Resources Canada - Geological Survey of Canada) | Sanei, Hamed (Natural Resources Canada - Geological Survey of Canada)
This study was carried out to investigate the relationship between rock properties and gas wetness, in order to better identify and characterize sweet spot areas. The study was conducted in two horizontal wells penetrating across a local CGR anomaly in the Montney Formation silty sand tight gas reservoir.
First, the relation between mud gas components and CGR distribution was surveyed to confirm the applicability of mud gas wetness as a proxy for CGR of initial production gas. Second, permeability indices of drill cuttings were analyzed by laboratory NMR measurements and the relationship of permeability to solid bitumen saturation was examined. In addition, MICP-derived properties and QEMSCAN mineralogy are discussed. The results were examined with respect to changes in mud gas wetness in the surveyed wells.
In the study area, a strong positive correlation was found between produced gas CGR and mud gas wetness ratio. Mud gas wetness was negatively correlated to cuttings permeability and permeability was negatively correlated to bitumen saturation, suggesting methane migration occurred along high permeability, low bitumen saturation pathways. Based on these observations, both mud gas wetness and cuttings permeability indices were confirmed to be effective for detecting liquids-rich areas in under-developed areas.
The liquid content of produced hydrocarbon gas (or condensate gas ratio, CGR) is an important factor for detecting sweet spot areas in tight gas reservoirs.
The Lower Triassic Montney Formation is currently a prolific gas producer in the Western Canadian Sedimentary Basin and is projected to continue as a major energy resource in the future. Gaseous hydrocarbons are said to be originally accumulated as oil and then thermally transformed to gas during further burial of the reservoir horizon (Sanei et al., 2013).
The abundant hydrocarbon resources in low-permeability formations are now technically accessible because of advances in the drilling and completion of multilateral/multifractured horizontal wells. However, measurement and modeling of petrophysical properties, required for reserves estimation and reservoi engineering calculations, are the remaining challenges for the development of tight formations. In particular, characterizing wettability (wetting affinity) of tight rocks is challenging because of their complex pore structure, which can be either in hydrophobic organic materials or in hydrophilic inorganic materials. We conduct comparative and systematic imbibition experiments on 10 twin core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact-angle and imbibition data indicate that the formation has a stronger affinity to oil than to water. However, the ratio between oil and water uptake of these samples is usually higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic-pore network that is partly composed of degraded bitumen. We also define a wettability index on the basis of the equilibrium oil and water uptake of the twin samples. Oil-wettability index is positively correlated with total organic carbon and clay content of the rocks, which generally increase from the upper Montney to the lower Montney.
Goodarzi, Fariborz (FG&Partners Ltd, 219 Hawkside Mews, NW, Calgary, Alberta, Canada, T3G 3J4) | Ardakani, Omid Haeri (Geological Survey of Canada - Calgary) | Pedersen, Per-Kent (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4) | Sanei, Hamed (Geological Survey of Canada - Calgary, Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4)
Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of 60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness.
Ghanizadeh, Amin (University of Calgary) | Aquino, Samuel (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Haeri-Ardakani, Omid (Geological Survey of Canada) | Sanei, Hamed (Geological Survey of Canada)
The results from an ongoing laboratory study investigating petrophysical and geomechanical characteristics of the Montney and Bakken formations in Canada are presented. The primary objectives are to 1) fully characterize the pore network (porosity, pore size distribution) and fluid transport (permeability) properties of these formations in areas with limited datasets; 2) investigate the interrelationship between petrophysical and geomechanical characteristics of these fine-grained tight reservoirs; and 3) analyze the effects of different geological factors on porosity, pore size distribution and permeability. The techniques used for characterization include: Rock-Eval pyrolysis (Tmax, TOC); bitumen reflectance; petrography (grain size); helium pycnometry; low-pressure gas (N2) adsorption (surface area, pore size distribution); pressure-decay profile permeability, pulse-decay and crushed-rock gas (N2, He) permeability; fracture permeability and mechanical hardness tests.
Rock-Eval analysis and microscopic observations indicate that most samples are organic-lean (average TOC content: 0.3%), ranging from fine-grained siltstone to very fine-grained sandstone (grain size: 31.8-53.7 μm). The measured pulse-decay and crushed-rock permeability values increase significantly with increasing porosity (2.1-14.1%), ranging between 1.1·10-6 and 7.3·10-2 mD. For the plugs analyzed (“as-received”), profile (probe) permeability values (9.1·10-4 - 6.7·10-3 mD) are consistently higher than pulse-decay (1.6·10-5 - 9·10-4 mD) and crushed-rock (1.1·10-6 - 5.4·10-5 mD) permeability values. Corrected profile (probe) permeability values for “in-situ” effective stress (5.3·10-5 - 1·10-3 mD) are, however, comparable with the pulse-decay (1.6·10-5 - 9·10-4 mD) permeability values. Unpropped fracture permeability, determined using an innovative procedure in this work, can be significantly (up to eight orders of magnitude) higher than matrix permeability under similar effective stress conditions. The grain size and mechanical hardness data are correlated to permeability. The dominant pore throat diameter controlling fluid flow is estimated for all samples using Winland-style correlations; these values agree with those obtained from low-pressure N2 adsorption analysis.
Applying multiple innovative analysis techniques on a large number of samples (26 m of slabbed core, 22 core plugs and their accompanying cuttings), this study provides a roadmap to fully characterize the fluid storage and transport properties of fine-grained tight oil and liquid-rich gas reservoirs. We demonstrate that pore structure, large- and fine-scale (cm-size) permeability heterogeneity, and mechanical characteristics of tight oil and liquid-rich gas reservoirs can be suitably-characterized using the methods we have used with application to flow-unit identification and mechanical stratigraphy determination. We further present useful correlations between petrophysical and geomechanical properties for the reservoirs studied.
The abundant hydrocarbon resources in low-permeability formations are now technically accessible due to advances in drilling and completion of multi-lateral/multi-fractured horizontal wells. However, measurement and modeling of petrophysical properties, required for reserve estimation and reservoir-engineering calculations are the remaining challenges for the development of tight formations. In particular, characterizing wettability (wetting affinity) of tight rocks is challenging due to their complex pore structure, which can be either in hydrophobic organic materials or in hydrophilic inorganic materials.
We conduct comparative and systematic imbibition experiments on ten binary core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact angle and imbibition data indicate that the formation has a stronger affinity to oil than to water. However, the ratio between oil and water uptake of these samples is usually higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic pore-network that is partly composed of degraded bitumen. We also define a wettability index based on the equilibrium oil and water uptake of the binary samples. Oil wettability index is positively correlated with Total Organic Carbon (TOC) and clay content of the rocks which increase with depth from the Upper Montney to the Lower Montney.
Rapid increase of energy demand has shifted the focus of petroleum industry towards vast unconventional resources worldwide. Advances in horizontal drilling and multi-stage hydraulic fracturing have unlocked shale and tight formations, which have become reliable hydrocarbon sources in North America. A tight gas reservoir is known by its extremely low permeability (less than 0.1 millidarcy (Juris et al 1971; Barree et al 2009; Tadayoni 2012)). Successful and sustainable development of such reservoirs requires correct characterization of reservoir properties (Barree et al 2009). In particular, knowing the reservoir rock properties such as permeability, porosity and wettability (wetting affinity) is critical for reserve estimation, production forecasting and designing optimum fracturing and treatment fluids.
The affinity of a reservoir rock to a particular fluid is defined as wettability, which depends on various factors such as rock mineralogy and the properties of the materials coating the rock surface (Anderson 1986; Rao et al 1994; Hamon 2000; Alotaibi et al 2010; Mohammadlou et al. 2012). Characterizing the wettability of reservoir rocks is important for 1) selecting fracturing and treatment fluids, 2) investigating residual phase saturation, and its pore-scale topology, 3) investigating the occurrence of water blockage at fracture face, and 4) selecting relevant capillary pressure and relative permeability models for reservoir engineering calculations. Various techniques such as modified Amott test, the U.S. Bureau of Mines (USBM) tests, contact angle measurement and spontaneous imbibition (Anderson 1986; Olafuyi et al 2007; Odusina et al. 2011) have been used to characterize wettability of reservoir rocks (Morrow et al. 1994; Zhou et al 2000; Mohanty et al 2013). However, conventional methods such as modified Amott and USBM can hardly be applied for measuring wettability of tight rocks primarily due to their extremely low permeability and mixed-wet characteristics (Sulucarnain et al 2012). Thus, it is more practical to characterize wettability of tight rocks by conducting and analyzing spontaneous imbibition experiments (Ma et al. 1999; Zhang et al. 1996; Takahashi et al. 2010). During spontaneous imbibition, the non-wetting phase initially saturating the porous medium is naturally displaced by a wetting phase.