Duvernay Formation Research Articles

Influence of geological setting on stress released by hydraulic fracture-induced earthquakes

Recent studies of injection-induced seismicity suggest that induced events have lower stress drops than tectonic earthquakes, suggesting stress drop can potentially be used as a discriminant parameter between natural and anthropogenic earthquakes. The main physical mechanisms responsible for low stress drop earthquakes, that is earthquakes that release less stress during failure than the average natural earthquake in a similar tectonic setting, are related to the increase in pore pressure and fault lubrication that result from the presence of fluids on the fault surface. Fluids reduce the effective normal stress applied on a fault allowing it to slip under lower stress conditions. Hough (2014) found that induced earthquakes have a factor of 2 to 10 lower stress drops relative to natural earthquakes, for 11 injection-induced moderate earthquakes in central and eastern United States based on their intensity reports. Sumy et al. (2016) also found a factor of 10 difference between the stress drops of natural and induced earthquakes when studying 87 Mw1.8 to Mw3.5 induced earthquakes in Oklahoma. A few other studies found opposing results. Huang et al. (2016) found the stress drops of 25 small earthquakes in central Arkansas to be comparable to Californian tectonic earthquake stress drops, and Viegas and Abercrombie (2011) also found the stress drops of a sequence of moderate earthquakes in Colorado to be comparable to the stress drops of Californian earthquakes. However, Viegas and Abercrombie (2011) noted that Central and North America intraplate earthquakes are expected to have higher stress drops than plate boundary California earthquakes (Viegas et al., 2010) making the comparison a false equivalency. Small earthquakes recorded during two hydraulic fracturing treatment programmes targeting stratigraphically equivalent formations in two regions of the Western Canadian Sedimentary Basin (Muskwa in Horn River Basin and Duvernay in Fox Creek), show very different stress drop estimates. Earthquakes in the Horn River Basin show lower stress drops by a factor of 10 to 20 than earthquakes in Fox Creek (Duvernay Basin). While the seismic events from both sites are generated during similar injection programsme, we propose that the differences in the observed stress drops are caused by different regional stress characteristics, as reflected by the differences in geology. The Horn River Basin stratigraphy is dominantly horizontal, whereas the Fox Creek region is characterized by the presence of the Leduc Formation reefs. These dolomitized reef complexes cross-cut the Duvernay shale formation, where both the Duvernay and overlying Ireton formations drape over the reef facies (Stoakes, 1980). We propose that earthquakes occurring in higher stressed regions have higher stress drops, as these regions are subjected to higher strain rates and store larger amounts of elastic strain.

Duvernay shale lithofacies distribution analysis in the West Canadian Sedimentary Basin

In the West Canadian Sedimentary Basin (WCSB), Duvernay shale is considered to contribute most of the Canadian shale gas reserve and production. According to global shale gas exploration and development practice, reservoir property and well completion quality are the two key factors determining the shale gas economics. The two key factors are strongly depending on shale lithofacies. On the basis of inorganic mineralogy theory, all available thin section, X-ray diffraction, scanning electron microscope (SEM), energy dispersive spectrometer (EDS) data were used to assist lithofacies analysis. Gamma ray (GR), acoustic (AC), bulk density (RHOB), neutron porosity (NPHI) and photoelectric absorption cross-section index (PE) were selected for log response analysis of various minerals. Reservoir representative equation was created constrained by quantitative core analysis results, and matrix mineral percentage of quartz, carbonate, feldspar and pyrite were calculated to classify shale lithofacies. Considering the horizontal continuity of seismic data, rock physics model was built, and acoustic impedance integrated with core data and log data was used to predict the horizontal distribution of different lithofacies. The results indicate that: (1) nine lithofacies can be categorized in Duvernay shale, (2) the horizontal distribution of different lithofacies is quite diversified, siliceous shale mainly occurs in Simonette area, calcareous shale is prone to develop in the vicinity of reef, while calcareous-siliceous shale dominates in Willesdon Green area.

Seismicity curbed by lowering volume

Induced Seismicity Determining why hydraulic fracturing (also known as fracking) triggered earthquakes in the Duvernay Formation in Canada is important for future hazard mitigation. Schultz et al. found that injection volume was the key operational parameter correlated with induced earthquakes in the Duvernay. However, geological factors also played a considerable role in determining whether a large injection volume would trigger earthquakes. These findings provide a framework that may lead to better forecasting of induced seismicity. Science , this issue p. [304][1] [1]: /lookup/doi/10.1126/science.aao0159

Shale oil and gas resources in organic pores of the Devonian Duvernay Shale, Western Canada Sedimentary Basin based on petroleum system modeling

Shale-hosted hydrocarbons is regarded as an important unconventional resource around the world. So far, huge emphasis has been put on the contribution of organic pores to self-source and self-reservoir hydrocarbon systems. This study systemically reveals the contribution of organic pores to hydrocarbon potential in the Duvernay Shale through restoring thermal maturity evolution, modeling hydrocarbon generation and expulsion in the Duvernay Formation, analyzing absorption capacity variation with TOC and modeled pore pressure, determining free-gas storage capacity with calculated organic porosity and correction of adsorbed gas, and calculating in-place shale oil and gas volumes with volumetric method. The Duvernay Shale reached “oil window” and “gas window” about 70–80 Ma and 50 Ma ago, respectively. Significant hydrocarbon generation (20% TR) began and terminated (95% TR) at Ro of 0.65% and 1.85%, respectively. Gas generation rates increased dramatically from Ro of 1.1%, while the instantaneous HC1-4 expulsion reached peak at Ro of 1.66%, the difference between which indicates considerable retained gas resource in Duvernay Shale. The gas storage capacity, including absorption capacity and free gas capacity, varies significantly in the Duvernay Shale, specifically, the former rangs from 8 to 30scf/ton, and the latter from 40 to 140scf/ton. The estimated median value of total in-place natural gas (GIP) and in-place oil resource (OIP) in organic pores of Duvernay shale are 404.8 TCF and 81420 MMbbl, respectively. Thus, the organic porosity is one of the keys to make the Duvernay Shale a successful play.

Seismic reservoir characterization of Duvernay shale with quantitative interpretation and induced seismicity considerations — A case study

The Devonian Duvernay Formation in northwest central Alberta, Canada, has become a hot play in the past few years due to its richness in liquid and gaseous hydrocarbon resources. The oil and gas generation in this shale formation made it the source rock for many oil and gas fields in its vicinity. We attempt to showcase the characterization of Duvernay Formation using 3D multicomponent seismic data and integrating it with the available well log and other relevant data. This has been done by deriving rock-physics parameters (Young’s modulus and Poisson’s ratio) through deterministic simultaneous and joint impedance inversion, with appropriate quantitative interpretation. In particular, we determine the brittleness of the Duvernay interval, which helps us determine the sweet spots therein. The scope of this characterization exercise was extended to explore the induced seismicity observed in the area (i.e., earthquakes of magnitude [Formula: see text]) that is perceived to be associated with hydraulic fracture stimulation of the Duvernay. This has been a cause of media coverage lately. We attempt to integrate our results with the induced seismicity data available in the public domain and elaborate on our learning experience gained so far.

Source characteristics and geological implications of the January 2016 induced earthquake swarm near Crooked Lake, Alberta

On 2016 January 12, an intraplate earthquake with an initial reported local magnitude (ML) of 4.8 shook the town of Fox Creek, Alberta. While there were no reported damages, this earthquake was widely felt by the local residents and suspected to be induced by the nearby hydraulic-fracturing (HF) operations. In this study, we determine the earthquake source parameters using moment tensor inversions, and then detect and locate the associated swarm using a waveform cross-correlation based method. The broad-band seismic recordings from regional arrays suggest a moment magnitude (M) 4.1 for this event, which is the largest in Alberta in the past decade. Similar to other recent M ∼ 3 earthquakes near Fox Creek, the 2016 January 12 earthquake exhibits a dominant strike-slip (strike = 184°) mechanism with limited non-double-couple components (∼22 per cent). This resolved focal mechanism, which is also supported by forward modelling and P-wave first motion analysis, indicates an NE–SW oriented compressional axis consistent with the maximum compressive horizontal stress orientations delineated from borehole breakouts. Further detection analysis on industry-contributed recordings unveils 1108 smaller events within 3 km radius of the epicentre of the main event, showing a close spatial-temporal relation to a nearby HF well. The majority of the detected events are located above the basement, comparable to the injection depth (3.5 km) on the Duvernay shale Formation. The spatial distribution of this earthquake cluster further suggests that (1) the source of the sequence is an N–S-striking fault system and (2) these earthquakes were induced by an HF well close to but different from the well that triggered a previous (January 2015) earthquake swarm. Reactivation of pre-existing, N−S oriented faults analogous to the Pine Creek fault zone, which was reported by earlier studies of active source seismic and aeromagnetic data, are likely responsible for the occurrence of the January 2016 earthquake swarm and other recent events in the Crooked Lake area.

Chemical and toxicological characterizations of hydraulic fracturing flowback and produced water

Hydraulic fracturing (HF) has emerged as a major method of unconventional oil and gas recovery. The toxicity of hydraulic fracturing flowback and produced water (HF-FPW) has not been previously reported and is complicated by the combined complexity of organic and inorganic constituents in HF fluids and deep formation water. In this study, we characterized the solids, salts, and organic signatures in an HF-FPW sample from the Duvernay Formation, Alberta, Canada. Untargeted HPLC-Orbitrap revealed numerous unknown dissolved polar organics. Among the most prominent peaks, a substituted tri-phenyl phosphate was identified which is likely an oxidation product of a common polymer antioxidant. Acute toxicity of zebrafish embryo was attributable to high salinity and organic contaminants in HF-FPW with LC50 values ranging from 0.6% to 3.9%, depending on the HF-FPW fractions and embryo developmental stages. Induction of ethoxyresorufin-O-deethylase (EROD) activity was detected, due in part to polycyclic aromatic hydrocarbons (PAHs), and suspended solids might have a synergistic effect on EROD induction. This study demonstrates that toxicological profiling of real HF-FPW sample presents great challenges for assessing the potential risks and impacts posed by HF-FPW spills.

Inversion of source rock hydrocarbon generation kinetics from Rock-Eval data

Basin and petroleum system modeling requires source rock kinetics as input for the reconstruction of hydrocarbon generation history. For less well-studied petroleum systems, there may be little information on petroleum generation kinetic parameters publically available; thus, an analog of representative source rock kinetics must be chosen from available kinetics databases. Recent studies suggest that source rock kinetics may vary considerably even when they contain the same type of kerogen. Thus, kinetic parameters from analog basins/source rocks may lead to erroneous results in petroleum generation history reconstruction. Rock-Eval data contain information about source rock kinetics, and can be used to improve the kinetic model in petroleum system modeling. However, the kinetic information in Rock-Eval data is not in the form of activation energies and frequency factors required to solve the temperature dependency of reaction rate in the Arrhenius equation. This article proposes a kinetic inversion method so that the analogous kinetic model chosen by the user can be improved based on Rock-Eval data of the targeted source rock. We demonstrate the method using a synthetic dataset in a case study for method validation and its application to real source rock evaluation for examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin (WCSB).

A seismological overview of the induced earthquakes in the Duvernay play near Fox Creek, Alberta

AbstractThis paper summarizes the current state of understanding regarding the induced seismicity in connection with hydraulic fracturing operations targeting the Duvernay Formation in central Alberta, near the town of Fox Creek. We demonstrate that earthquakes in this region cluster into distinct sequences in time, space, and focal mechanism using (i) cross‐correlation detection methods to delineate transient temporal relationships, (ii) double‐difference relocations to confirm spatial clustering, and (iii) moment tensor solutions to assess fault motion consistency. The spatiotemporal clustering of the earthquake sequences is strongly related to the nearby hydraulic fracturing operations. In addition, we identify a preference for strike‐slip motions on subvertical faults with an approximate 45° P axis orientation, consistent with expectation from the ambient stress field. The hypocentral geometries for two of the largest‐magnitude (M ~4) sequences that are robustly constrained by local array data provide compelling evidence for planar features starting at Duvernay Formation depths and extending into the shallow Precambrian basement. We interpret these lineaments as subvertical faults orientated approximately north‐south, consistent with the regional moment tensor solutions. Finally, we conclude that the sequences were triggered by pore pressure increases in response to hydraulic fracturing stimulations along previously existing faults.

A depositional model for organic-rich Duvernay Formation mudstones

The Upper Devonian Duvernay Formation of western Canada is an organic-rich shale formation now targeted as a hydrocarbon reservoir. We present a detailed sedimentological analysis of the Duvernay Formation in order to better understand organic-rich mudstone depositional processes and conditions and to characterize the vertical and lateral heterogeneity of mudstone lithofacies that affect petrophysical and geomechanical rock properties. Organic-rich mudstone facies of the Duvernay Formation were deposited in a dynamic depositional environment by a variety of sediment transport mechanisms, including suspension settling, turbidity currents, and bottom water currents in variably oxygenated bottom waters. Suspension settling dominated in distal relatively deep areas of the basin, but evidence for weak turbidity currents and bottom water currents was observed in the form of graded beds and thin grain-supported siltstone laminae. Organic enrichment primarily occurred in distal areas as a result of bottom water anoxia and low depositional rates of inorganic sediment. In deep water locations near platform margins, alternating silty-sandy contourite beds and organic-rich mudstone beds are present, the former interpreted to have been deposited and reworked by bottom water currents flowing parallel to slope. In shallower, more oxygenated settings, mudstone lithologies vary from calcareous to argillaceous. These sediments were deposited from suspension settling, turbidity currents, and bottom water currents, although primary sedimentary structures are often obscured by extensive bioturbation. Locally, organic enrichment in dysoxic rather than anoxic bottom waters was driven by a slightly increased sedimentation rate and possibly also by aggregation of sedimentary particles in the water column due to interaction between organic matter and clay minerals. Large variations observed in sediment composition, from siliceous to calcareous to argillaceous, reflect multiple biogenic, carbonate, and clastic sediment sources. Sediment composition is influenced by basin morphology, circulation patterns, sea level variation, and proximity to sediment sources.

Organic shale wettability and its relationship to other petrophysical properties: A Duvernay case study

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 wettability of the shale samples with a wide range of TOC (2.2–6.6wt%), effective porosity (2.0–6.2% BV), and kerogen maturity (wet-gas, dry-gas, and over-mature). We characterize the samples by measuring the effective porosity, pressure-decay permeability, oil saturation, bulk density, matrix density, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. To investigate the effects of pore connectivity, we also measure spontaneous imbibition and contact angles of oil and water on crushed shale packs and compare the results with those of similar tests on the core plugs. We also investigate the crossplots of effective porosity, pressure-decay permeability, bulk density, matrix density, oil saturation, and TOC content, by using 130 data points from samples of the five wells.Analysis of the data reveals a positive correlation of TOC content with effective porosity, pressure-decay permeability, and oil saturation of the samples. Bulk density and matrix density of the core samples decrease with increasing the TOC content. The crossplots indicate that the majority of pores exist in the organic matter of the samples and these organic pores have high affinity towards oil. Scanning Electron Microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses also demonstrate an abundant number of small nanopores within the organic matter. These hydrophobic small nanopores with diameters <100nm may explain high imbibed volume of oil compared with that of brine, and also late equilibrium of oil imbibition. SEM and EDS analysis also show large micropores bordered by inorganic minerals. According to Handy's model, these hydrophilic micropores with diameters >1000nm may explain early equilibrium of brine in spontaneous imbibition experiments. We define pore wettability index of oil (PWIo) and brine (PWIw) based on the imbibition rate of oil and brine, respectively. PWIo is greater than PWIw in all spontaneous imbibition tests. Higher PWIo compared with PWIw indicates that oil preferentially flows through smaller pores while brine prefers to flow through larger pores. We also 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 effective porosity have higher WIo. Positive correlations of WIo with TOC content and effective porosity suggest that the majority of hydrophobic connected pores exist in the organic part of the rock. In addition, we observe negative correlation of WIo with oxygen index (OI). This observation can be explained by 1) higher number of organic nanopores, and 2) stronger oil-wetness of kerogen in samples with higher kerogen maturity (lower OI).

Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale

Summary Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the US Energy Information Administration, approximately 90% of the oil-production growth comes from six tight-oil plays. The Eagle Ford is one of these plays, and it accounts for 33% of the oil-production growth with a contribution of 1.3 million B/D. This is outstanding. However, oil recoveries as a percentage of the original oil in place (OOIP) are extremely low. This must be improved. A geological challenge in the Eagle Ford shale is the understanding of unconventional fluids distribution over geologic time: Shallower in the structure, there is black oil; deeper and to the south; condensate appears; and at the bottom, dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other unconventional reservoirs (e.g., Duvernay shale in Canada). The low oil recovery and the unusual distribution of fluids led to the key objective of this paper—to identify the main factors that control fluid migration (caused by buoyancy of gas in oil) from one zone to another through geologic time. This was performed by constructing a conceptual cross-sectional compositional simulation model with northwest/southeast orientation that allowed the study of fluid migration, fluid distribution, and fluid contacts throughout 1 million years while maintaining computational time within reasonable limits. The controlling parameters studied were porosity, permeability, pore-throat aperture (rp35), and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same original distribution (i.e., approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact). These fluids are the target of an ongoing research project with the ultimate goal of improving oil recovery from tight reservoirs by means of enhanced oil recovery (EOR) (Fragoso et al. 2015). There is, however, some gas migration through natural fractures to the top of the structure. This migration is interpreted in this study to be responsible for higher initial gas production in some oil wells in the top of the structure. Some operators indicate, however, that rapid gas/oil-ratio increases in the updip oil region are the result of low reservoir pressures and the rapid onset of two-phase flow. It would probably take geochemical evidence to support this conclusion.

Characterization of multi-fractured horizontal shale wells using drill cuttings: 2. Permeability/diffusivity estimation

There is considerable research interest in the transport properties of shales to assist in their evaluation as reservoirs for natural gas and oil. However, shales have proven difficult to characterize, in part because of the challenges of obtaining viable reservoir samples from multi-fractured horizontal wells used to produce from them. Often the only reservoir samples available from horizontal wells are drill cuttings – the sample sizes obtained from cuttings are typically too small for quantitative analysis using conventional techniques. Therefore, new, high-precision methods are required to analyze the smaller cuttings samples. Further, the physics of gas storage and transport through the multi-model pore structure of shale is complex, requiring rigorous modeling approaches to extract parameters of interest such as permeability/diffusivity.In this work, the use of a high-precision, low-pressure adsorption device is explored for extracting permeability/diffusivity parameters from small amounts (1–2 g) of artificial (crushed core sample) drill cuttings of Duvernay shale. In order to extract the transport parameters, gas flow through the complex, heterogeneous matrix pore structure of the shale has been approximated using a general dual porosity numerical model which assumes that (1) gas flows through macropores by continuum viscous flow (2) gas flows through meso and micropores by Knudsen diffusion and molecular slippage on pore walls and (3) adsorption occurs in meso and micropores. The model can be simplified into two sub-models, a macro/micropore system or meso/micropore system, depending on the measured pore size distribution of the samples of interest.The new multi-pore (bidisperse) numerical model is applied to carbon dioxide low-pressure adsorption rate data obtained from the crushed Duvernay shale core samples, and apparent permeability for each gas/sample group is calculated at different pressure steps. The low-pressure adsorption device yields pressure-time data that is of much better quality than a commercial crushed rock permeability device that requires larger sample sizes. The new bidisperse pore structure numerical model, which allows permeability to vary (at each pressure step) due to gas slippage effects, properly describes the entire adsorption rate history of the samples studied. Mesopore apparent permeabilities range from1 × 10−2–1 × 10−3 mD and micropore apparent diffusivities are in the 1 × 10−7 mD range. The calculated apparent diffusivities obtained from modeling adsorption rate data change with pressure.The results of this study have important implications for shale matrix transport characterization. The resulting data can be used for making completions decisions and in reservoir models which capture reservoir property changes along a horizontal lateral.

A revised method for organic porosity estimation in shale reservoirs using Rock-Eval data: Example from Duvernay Formation in the Western Canada Sedimentary Basin

Studies suggest that nanometer-scale pores exist in organic matter as a result of thermal decomposition of kerogen. Depending on the host rock lithology, organic pores could be the primary storage for hydrocarbon accumulation in unconventional petroleum plays. Although various methods are publicly available, estimation of organic porosity remains a challenge because the procedures involve certain simplification or some implicit assumptions on the calculation of initial total organic carbon (TOC). In this study, we propose a revised method to address some of these issues. A model of estimating hydrocarbon expulsion efficiency is developed and incorporated into the calculation of initial TOC, thus producing an estimate of organic porosity with an improved mass balance. The method has been tested and compared with estimates using other methods based on a Rock-Eval data set in the literature. An application of the method to a large data set from the Upper Devonian Duvernay Formation petroleum system in the Western Canada Sedimentary Basin reveals that the modification has a significant effect on the estimated organic porosity. This study also indicates that organic porosity in the Duvernay Formation ranges greatly from none in immature intervals to >6% in highly mature and organic-rich shale intervals. Scanning electron microscope images of immature and mature organic-rich shale samples of the Duvernay Formation show a progressive increase in organic porosity with increasing thermal maturity, supporting the proposed model calculation. The presence of a large volume of organic porosity in mature shale intervals suggests a significant amount of hydrocarbon may be stored in the organic nanopores in the Duvernay Formation.

Organic matter characterization in mixed hydrocarbon producing areas within the Duvernay Formation, Western Canada Sedimentary Basin, Alberta

This paper characterizes organic matter in the mixed hydrocarbon (oil–dry gas, oil–condensate) producing areas of the Late Devonian Duvernay Formation in Alberta (Canada) by high-resolution RockEval data (n=246) and petrography (n=35) at three drillhole locations (Locations A and C distal, Location B proximal to Leduc Reef, respectively). Total organic carbon (TOC) ranges from 0.15–6.22wt.% at Location A, 0.43–8.20wt.% at Location B, and 1.84–5.23wt.% at Location C with an overall median value of 3.42wt.%. S2 values range from 0.20–7.42mgHC/g of rock at Location A, 0.22–4.23mgHC/g of rock at Location B, and 1.68–5.04mgHC/g of rock at Location C. These results for samples from Locations A, B and C indicate that kerogen is Type I to Type II. The hydrogen index (HI) of these rocks is significantly lower (<160mgHC/g TOC) than that of traditional oil-producing source rocks of this age (~400–700mgHC/g TOC). At Locations A and C, Tmax lies within the oil window with a mean value of 459°C; at Location B, Tmax varies greatly between 434 and 488°C, between the oil and gas window, with no observable association with sample depth. Vitrinite reflectance of samples ranges from 0.99–1.32%. Tmax values do not correlate with vitrinite reflectance of the samples (R2=0.04), nor with depth (R2=0.4), suggesting that Tmax is not a reliable indicator of thermal maturity in this system. Low TOC/S2, high mineral carbon is associated with intervals of intergrown sparry calcite and pyrite in petrographic samples at Location B. Organic matter within the Duvernay Formation was characterized as almost entirely solid bitumens, with very minor inertinite, <1% by volume). The RockEval and petrographic observations suggest that secondary diagenetic effects are the cause for the mixed hydrocarbon signature, rather than any spatial variation in depositional environment or thermal maturation regimes.

Source analysis of a potential hydraulic‐fracturing‐induced earthquake near Fox Creek, Alberta

AbstractAn earthquake with a reported magnitude of 4.4 (ML) was detected on 13 June 2015 in western central Alberta, Canada. This event was the third felt earthquake this year near Fox Creek, a shale gas exploration region. Our results from full moment tensor inversions of regional broadband data show a strong strike‐slip mechanism with near‐vertical fault plane solutions. The decomposition of the moment tensor solution is overwhelmingly double couple, while only a modest (∼20%) contribution is attributed to compensated‐linear‐vector‐dipole. The depth of this earthquake is 3–4 km, near the base of the sedimentary layer, and the moment magnitude (M= 3.9) of this event is considerably smaller than the initial reportedMLvalue. The hypocenter location, depth, and mechanism are favorable to a possible association between this earthquake and hydraulic fracturing operations within the Duvernay shale.

Revised models for determining TOC in shale play: Example from Devonian Duvernay Shale, Western Canada Sedimentary Basin

Determination of total organic carbon (TOC) is essential in unconventional shale resource play evaluation. Indirect method, such as petrophysical approach, can provide a fast, convenient and cost efffective means for TOC estimation from well logs. Among the publically available approaches, the ΔlogR method is a popular one in conventional source rock evaluation and has been applied to unconventional resource play evaluation by many practitioners. Careful examination of the method finds that improvements can be made for a better TOC estimation with relaxed limitations. This study proposes the following revisions on the original ΔlogR method: 1) allowing estimation of petrophysical parameters from the targeted source rock rather an assumed linear approximation, 2) using additional logs to improve TOC prediction, and 3) replacing LOM (level of organic metamorphism unit) with a more commonly used thermal indicator Tmax for convenience. Depending on data or preference, the choice of using different porosity logs (density versus sonic) and parameter estimation methods (cross-plot method versus data-driven approaches) makes the revised method flexible for application. We present the revisions along with application examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin to demonstrate the application of the improved ΔlogR method in shale gas evaluation. Comparison of the results from the revised method and the original one reveals that the revised models provide better and unbiased estimates of TOC with a higher correlation coefficient and bell-shaped residues centered at zero.

Hydrocarbon evaporative loss from shale core samples as revealed by Rock-Eval and thermal desorption-gas chromatography analysis: Its geochemical and geological implications

The S1 peak generated by Rock-Eval analysis of source rock and reservoir interval core and cuttings samples has been routinely employed for in-place hydrocarbon resources assessment by petroleum geochemists, geologists and even engineers. Significant evaporative loss of gaseous and light hydrocarbons (up to C10) can occur during core and cuttings collection and storage, and subsequent sample preparation in the laboratory before instrumental analysis. Consequently a correction to the S1 values is needed in order to obtain a more accurate estimate of the resources. To investigate the effect of evaporative loss on both the amount and the composition of the hydrocarbons retained in shale, a time-series of Rock-Eval and thermal desorption-gas chromatography (TD-GC) analyses have been carried out on an organic-rich Devonian Duvernay Formation shale core sample from the Western Canada Sedimentary Basin (WCSB) and an organic-lean Ordovician Lotbinière Formation shale core sample from Quebec, Canada. The results suggest that the content of total organic carbon (TOC) may play an important role in retaining and preserving light hydrocarbons in sedimentary rocks. A total loss of gaseous and light liquid hydrocarbons up to C9 is shown to take place within 21 h of sample preparation for the low TOC (<1%) Ordovician Lotbinière shale when the powdered sample was left exposed to the open air, accounting for a 38% decrease in its Rock-Eval S1 peak. The Rock-Eval S1 peak can be reduced by 29% even if the powdered sample has been stored in a sealed container for just over a week. In contrast, the volatile loss has been found to occur at a much slower rate for the high TOC (>11%) Devonian Duvernay shale core sample. After 360 h of exposure to the open air, the powdered Duvernay shale sample shows only 15% decline in its Rock-Eval S1 peak, and still contains high relative concentrations of C7–C9 hydrocarbons. In addition, the evaporative loss of some isomers of C5–C7 hydrocarbons from the organic-rich shale is not fully in agreement with their GC retention/elution behavior, but appears to be partially controlled by their adsorption/desorption on the organic matter and mineral matrix. This suggests that the C5–C8 gasoline range hydrocarbon parameters should be used with caution for oil–oil correlation for unconventional shale and tight petroleum systems. While the findings in this study validate the current industrial practice that targets organic-rich and mature shale intervals for unconventional shale gas and oil exploration because of their large hydrocarbon storage capacity, the results also have an important implication that high TOC content may adversely affect the production efficiency of shale and tight hydrocarbon reservoirs due to the strong adsorption of hydrocarbons by the high maturity organic matter.

Hydraulic fracturing and the Crooked Lake Sequences: Insights gleaned from regional seismic networks

AbstractWithin central Alberta, Canada, a new sequence of earthquakes has been recognized as of 1 December 2013 in a region of previous seismic quiescence near Crooked Lake, ~30 km west of the town of Fox Creek. We utilize a cross‐correlation detection algorithm to detect more than 160 events to the end of 2014, which is temporally distinguished into five subsequences. This observation is corroborated by the uniqueness of waveforms clustered by subsequence. The Crooked Lake Sequences have come under scrutiny due to its strong temporal correlation (&gt;99.99%) to the timing of hydraulic fracturing operations in the Duvernay Formation. We assert that individual subsequences are related to fracturing stimulation and, despite adverse initial station geometry, double‐difference techniques allow us to spatially relate each cluster back to a unique horizontal well. Overall, we find that seismicity in the Crooked Lake Sequences is consistent with first‐order observations of hydraulic fracturing induced seismicity.

A comparison of shale permeability coefficients derived using multiple non-steady-state measurement techniques: Examples from the Duvernay Formation, Alberta (Canada)

Matrix permeability, while an important control on fluid flow in unconventional reservoirs, is difficult to measure in the laboratory. There are now multiple methods for laboratory determination of permeability for shales, but little consensus on the appropriate method for permeability measurement. Each technique is based on different physical principles and utilizes reservoir samples at different scales. The combination of sample size and preparation and measurement conditions can lead to a wide range in permeability estimates, creating confusion for recipients of the data. In this work, we compare different non-steady state methods for determination of gas permeability in low-permeability Canadian shales and provide insight into the causes of permeability variation. Further, we analyze and discuss the effects of different controlling factors including porosity, pore-fluid content, mineralogy and effective stress on permeability.Gas permeability measurements were conducted on low-permeability (shale) samples from the Duvernay Formation (Alberta, Canada) using three different methods: profile (probe), pulse-decay and crushed-rock permeability techniques. The analyzed samples differ in total organic carbon (TOC) content, pore network characteristics (porosity, pore size distribution), pore-fluid content (“as-received” and cleaned/dried) and mineralogy. Profile (probe) and crushed-rock permeability measurements were performed on samples in the “as-received” and cleaned/dried conditions. Pulse-decay measurements were conducted on samples in the cleaned/dried state. Helium pycnometry/expansion measurements were performed using “as-received” and cleaned/dried samples under unconfined and controlled “in situ” effective stress conditions.Permeability values derived for the Duvernay samples are strongly dependent on measurement technique, sample size and sample conditions. In the “as-received” state, profile (probe) permeability values, both uncorrected (3.7×10−4–2.7×10−2mD) and corrected (1.5×10−5–5.7×10−4mD) for “in-situ” stress, are consistently higher than crushed-rock (3.7×10−7–5.9×10−6mD) permeability values. Similarly, in the cleaned/dried state, profile (probe) permeability values, both uncorrected (1.9×10−2–1.2mD) and corrected (5.8×10−5–1.4×10−2mD) for “in-situ” stress, are consistently higher than pulse-decay (8.4×10−5–7.6×10−4mD) and crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. In the cleaned/dried state, pulse-decay permeability values (8.4×10−5–7.6×10−4mD) are comparable with crushed-rock (3.8×10−5–1.1×10−3mD) permeability values. Profile (probe) and crushed-rock permeability values measured on cleaned/dried samples are approximately two orders of magnitude higher than those measured on “as-received” samples.The observed discrepancies between permeability values derived from the various non-steady-state techniques is rationalized in terms of sample size, treatment, stress-state and physical principals of measurement. The combined use of these methods is however recommended to provide insight into the controls of sample heterogeneity at sub-cm scales, which is particularly important for shale samples.