Nisku Formation Research Articles

From oil field to geothermal reservoir: assessment for geothermal utilization of two regionally extensive Devonian carbonate aquifers in Alberta, Canada

Abstract. The Canadian province of Alberta has one of the highest per capita CO2-equivalent emissions in Canada, predominantly due to the industrial burning of coal for the generation of electricity and mining operations in the oil sands deposits. Alberta's geothermal potential could reduce CO2 emissions by substituting at least some fossil fuels with geothermal energy.The Upper Devonian carbonate aquifer systems within the Alberta Basin are promising target formations for geothermal energy. To assess their geothermal reservoir potential, detailed knowledge of the thermophysical and petrophysical rock properties is needed. An analogue study was conducted on two regionally extensive Devonian carbonate aquifers, the Southesk-Cairn Carbonate Complex and the Rimbey-Meadowbrook Reef Trend, to furnish a preliminary assessment of the potential for geothermal utilization. Samples taken from outcrops were used as analogues to equivalent formations in the reservoir and correlated with core samples of the reservoir. Analogue studies enable the determination and correlation of facies-related rock properties to identify sedimentary, diagenetic, and structural variations, allowing for more reliable reservoir property prediction.Rock samples were taken from several outcrops of Upper Devonian carbonates in the Rocky Mountain Front Ranges and from four drill cores from the stratigraphically equivalent Leduc Formation and three drill cores of the slightly younger Nisku Formation in the subsurface of the Alberta Basin. The samples were analyzed for several thermophysical and petrophysical properties, i.e., thermal conductivity, thermal diffusivity, and heat capacity, as well as density, porosity, and permeability. Furthermore, open-file petrophysical core data retrieved from the AccuMap database were used for correlation.The results from both carbonate complexes indicate good reservoir conditions regarding geothermal utilization with an average reservoir porosity of about 8 %, average reservoir permeability between 10−12 and 10−15 m2, and relatively high thermal conductivities ranging from 3 to 5 W m−1 K−1. The most promising target reservoirs for hydrothermal utilisation are the completely dolomitized reef sections. The measured rock properties of the Leduc Formation in the subsurface show no significant differences between the Rimbey-Meadowbrook Reef Trend and the Southesk-Cairn Carbonate Complex. Differences between the dolomitized reef sections of the examined Leduc and Nisku Formation are also minor to insignificant, whereas the deeper basinal facies of the Nisku Formation differs significantly.In contrast, the outcrop analogue samples have lower porosity and permeability, likely caused by low-grade metamorphism and deformation during the Laramide orogeny that formed the Rocky Mountains. As such, the outcrop analogues are not valid proxies for the buried reservoirs in the Alberta Basin.Taken together, all available data suggest that dolomitization enhanced the geothermal properties, but depositional patterns and other diagenetic events, e.g., fracturing, also played an important role.

Biodegradation characteristics of bitumen from the Upper Devonian carbonates (Grosmont and Nisku formations) in Alberta, Canada

In this study, we investigated the biodegradation processes of bitumen from the Upper Devonian carbonates (Grosmont and Nisku formations) in Alberta using GC and GC-MS analyses of four drilling cores. The analyzed samples contain notable rich extracted bitumen, which is predominantly composed of NSO and asphaltene compounds and has lesser amounts of saturated and aromatic hydrocarbons (HCs). The GC and GC-MS results for both saturated and aromatic HCs indicate that there are considerable variations among the samples, which are primarily attributed to the differences in the degree of biodegradation involving microbial activity. The sulfur content and its isotope values for the samples also support biodegradation. Three groups can be classified based on the biomarker distributions as follows: (1) in Group 1, C19-C25 tricyclic terpanes are most abundant, particularly the C23 compounds; (2) Group 2 has no C30-C35 αβ hopanes and more abundant 25-norhopanes than the other two groups; and (3) Group 3 is similar to Group 1, but generally has less abundant C19-C25 tricyclic terpanes than Group 1. The reservoir alteration processes have notably influenced the biomarker properties of the samples. The most pronounced effects are the reduction of the amounts of C30+ hopanes and increasing demethylated hopanes, particularly in Groups 1 and 2, but not in Group 3. For Group 3, unlike Group 1, the degradation of hopanes apparently does not result in demethylated hopanes, indicating that there is another pathway to produce hopanes and/or destroy demethylated hopanes. These findings indicate that the biodegradation processes that occurred in the Grosmont and Nisku formations have been spatially and vertically varied due to the different environmental conditions and microbial processes.

Evolution of Li-enriched oilfield brines in Devonian carbonates of the south-central Alberta Basin, Canada

There is a long and extensive history of study regarding the origins and characteristics of brines within the Alberta Basin of Canada. This study focuses on the origins of Li-enriched (>50 mg/kg) brines of the late Devonian Swan Hills, Nisku and Leduc Formations of the southwestern Alberta Basin. Available data show that two Li-enriched brines having distinctly different geochemical characteristics, and thus distinct evolutionary histories, exist within the late Devonian carbonates of the southwestern Alberta Basin. Li-enriched brine of the Swan Hills Formation appears to have been formed by dissolution of halite and mixing with Li-enriched fluids expelled from Precambrian crystalline basement. The degree of mixing between Swan Hills brines and meteoric water is unknown. Formation of Li-enriched brines in the Nisku and Leduc Formations could be explained by preferential dissolution of Li-enriched late-stage evaporite minerals, likely from the middle Devonian Prairie Evaporite Formation, into evapoconcentrated late Devonian seawater. Dense Li-enriched brine migrated downward into the underlying early Devonian Winnipegosis Formation and then westward in response to westward tilting beginning in Jurassic time. Li-enriched brine was then diluted by mixing with meteoric water driven into the Devonian of the southwestern Alberta Basin in response to hydraulic gradients created by the effects of Laramide tectonics.

Constraining Temperatures of Formation and Composition of Dolomitizing Fluids In the Upper Devonian Nisku Formation (Alberta, Canada) With Clumped Isotopes

Abstract Three dolomite phases in the burial dolomitization system of the Nisku Formation in central Alberta (Canada) were measured for carbonate clumped isotopes. Independent temperature constraints using fluid inclusions and traditional oxygen isotope geothermometry allow us to test the application of this method using a new calibration curve extrapolated to higher temperatures. These three phases of dolomite correspond to three diagenetic stages in the burial history. The oldest phase is replacive gray matrix dolomite formed during relatively shallow burial depths at average clumped-isotope temperatures (Δ47T) of +80 ±7°C. Previous temperature estimates from standard oxygen isotope geothermometry ranged from 50 to 80°C. A calculated δ18O(H2O) of 3 ± 1.4‰ VSMOW points to precipitation from Devonian seawater modified by evaporation and/or water–rock interaction. The first phase of saddle dolomite cement formed by pressure-solution during intermediate burial depths yielded average Δ47T of 96 ±4°C (previously calculated at ~80°C) and δ18O(H2O) of 4 ± 1‰ VSMOW. A second phase of saddle dolomite formed in association with thermochemical sulphate reduction during deep burial records average Δ47T of 151 ±5°C, comparable to fluid inclusion temperatures ranging from 125 to 145°C. The average δ18O(H2O) of the fluid that formed this saddle dolomite phase is calculated as 8 ± 1‰ VSMOW, suggesting much more advanced water–rock interaction. Δ47T are consistent with previous temperature estimates from a combination of geological data conventional O-isotope and fluid-inclusion thermometry. Another important finding is that the Δ47 signatures are preserved even after reaching deeper burial and/or during uplift and cooling, which points to a closure temperature in dolomites in excess of 180°C. Thus, dolomite appears to be a better phase for clumped-isotope analysis than calcite for rocks that have been exposed to higher temperatures upon further burial. This study demonstrates the power of the clumped-isotope thermometer to reconstruct complex diagenetic histories in burial diagenetic environments where multiple generations of diagenetic cements can be analyzed individually.

2-D reactive transport modeling of the fate of CO2 injected into a saline aquifer in the Wabamun Lake Area, Alberta, Canada

Carbon capture and storage (CCS) is a viable option to reduce emissions of anthropogenic CO2 into the atmosphere. One important component during the storage site selection process is the prediction of the movement and the fate of the injected CO2 in the chosen reservoir. The fate of CO2 injected into a saline aquifer of the Devonian Nisku Formation in Alberta (Canada) was simulated using the reactive transport code TOUGHREACT. A 2D radially symmetric model was developed for a 50-year CO2 injection phase followed by a 1000-year storage period. CO2 was injected into the bottom 10m of the Nisku Formation at a rate of 1Mton/year for 50years. The injected supercritical CO2 spread out radially up to 3.5km after 50years of injection and 6.0km after 1000years of post-injection. After 1000years, the injected CO2 was trapped in the Nisku Formation underneath the excellent seal of the Calmar shale predominantly as free CO2 via hydrodynamic trapping (76%) and to a lesser extent by solubility trapping (23%) in aqueous phase (HCO3-(aq)). Mineral trapping of injected CO2 in the Nisku aquifer was negligible. This study predicted the interactions of the fluids and rock minerals with injected CO2 in the storage Nisku aquifer, the Calmar caprock and the bottom rock Ireton shale. This information will be highly beneficial for potential future CO2 injection projects targeting the saline aquifer of the Nisku Formation in Western Canada.

Geothermal exploration of Paleozoic formations in Central Alberta

This study explores the distribution of Paleozoic formations in the Central Alberta Basin and investigates rock properties with regard to their usability as geothermal reservoirs. The study area of this regional-scale investigation is about 160 km × 200 km in size and located around Edmonton where the basin depth ranges between 1.8 and 3.5 km. A three-dimensional (3D) geological model was developed based on stratigraphic tops from about 7000 wells from the database of the Alberta Geological Survey (AGS). Spatial distribution and thickness of deep formations were established in the 3D geological model. Porosity and permeability of four Devonian carbonate formations — Cooking Lake, Leduc, and Nisku formations, and Wabamun Group — were investigated using data from more than 50 000 core analyses. Average porosity of the Devonian strata in the study area ranges from 4.5% (Nisku) to 8.7% (Wabamun), average permeability is between 3.5 × 10−15m2(Wabamun) and 26 × 10−15m2(Leduc). The distribution of both parameters was analyzed using geostatistical methods. Based on an average geothermal gradient and the geometry of formations from the 3D modeling study, an estimation of formation temperatures for the Paleozoic formations is presented. Temperature in the Cambrian Basal Sandstone Unit ranges from 62 °C in the shallower northeast (1.8 km) to 122 °C in the deeper southwest (3.5 km); temperature in the Devonian strata ranges from 22 to 87 °C. With these new results, potential geothermal reservoirs can be delineated in the Alberta Basin around Edmonton, enabling future detailed exploration and field development.

Resolution on multiples: Interpreters' perceptions, decision making, and multiple attenuation

We investigated our ability to remove a specific short-period multiple from the Nisku and Blueridge formations in West Central Alberta, Canada. This problem is commercial in nature, and has persisted because it was believed that the multiple had too little moveout to be removed, rendering interpretation of the thin Blueridge zone impossible. Associated with this issue was the belief that the modern high-resolution Radon transforms do not materially affect the stack response of real data in this area despite their excellent performance on synthetics and on other data in the literature. Serious technical work seldom affords a discussion of “beliefs”, but this work is concerned with the decision-making of the interpreter. We show that in order to address a specific, real, short-period multiple problem, the interpreter was required to challenge previously held technical assumptions. This required the interpreter to consider the nature of the multiple itself, the nature and limitations of the multiple suppression technology used, and to objectively measure the level of success in suppressing the multiple.

Hydrocarbon breaching of a regional aquitard: The Devonian Ireton Formation, Bashaw area, Alberta, Canada

This study is an investigation of aquitard characteristics and hydrocarbon entrapment in the Upper Devonian strata of the Bashaw area of Alberta, Canada. Oil and gas are trapped at two stratigraphic levels, the Leduc-aged Bashaw Reef Complex (D-3) and the Camrose Member–Nisku Formation (D-2), which are separated by a low-permeability aquitard of the Ireton Formation, a marl with variable carbonate content. The Ireton aquitard provides the principal control to cross-formational fluid flow in the area. Over much of the Bashaw Reef Complex, the Ireton aquitard ranges from approximately 25 m (82 ft) thick to less than 1 m (3.3 ft) over paleotopographic highs. Associated with thinning is a change in lithofacies and carbonate content from approximately 50% carbonate in the thicker, more basinal facies to more than 80% carbonate and shallower-water facies over the paleotopographic highs of the Leduc. Early replacement dolomitization, probably by density-driven reflux, generated intercrystal porosity on the order of 3 to 4% in the more carbonate-rich facies, which rendered these parts of the aquitard less effective to later hydrocarbon retention. Subsequent differential compaction of the underlying reef complex led to a raised rim morphology and, in places, to a thickness inversion of the Ireton aquitard, that is, a thicker Ireton aquitard draped over the Leduc raised rims. As a result, petroleum migration occurred primarily along the raised rims and was trapped within the present-day highs that are draped by more than 10 m (32.8 ft) of Ireton aquitard. Where the overlying Ireton aquitard drape is less than 10 m (32.8 ft) in thickness, breaching and remigration from Leduc traps into the overlying Nisku-Camrose traps may have occurred and/or can be suspected. Invariably, the Ireton aquitard was breached where its carbonate content exceeded approximately 80% and where it is less than 4 m (13.1 ft) thick. The critical controls to hydrocarbon breaching are pervasive dolomitization of the Ireton aquitard with high carbonate content, which enhanced porosity and permeability, and aquitard thickness. Many Nisku and Camrose pools are situated either directly above or updip from such breaches.

Biodegradation characteristics of bitumen from the Upper Devonian Grosmont reservoir, Alberta, Canada

Abstract The Upper Devonian Nisku Formation, Upper Ireton, and Grosmont Formation (collectively referred as the “Grosmont reservoir”) form a giant bitumen/heavy oil reservoir in Alberta, Canada with about 406 billion barrels of original oil in place. Because of the low quality of the hydrocarbons and the complex geology, the Grosmont reservoir was not deemed commercially viable until relatively recently. The Grosmont is now under consideration for commercial development by several companies and consortia due to technological advances and higher oil prices. One part of the work leading up to new pilot sites is the characterization of the degree of biodegradation in the Grosmont reservoir, which could be used as a proxy of the petrophysical properties of bitumen, specifically viscosity. In order to characterize the biodegradation in the Grosmont reservoir, a total of 18 samples selected from the Nisku, Upper Ireton, and Grosmont along a strike cross-section were examined by gas chromatography-mass spectrometry. Biomarker analysis indicates the Grosmont reservoir was subjected to extreme stages of biodegradation, demonstrated by the loss of regular steranes, strongly biodegraded hopanes, and reduced abundances of tricyclics and diasteranes. The rare geological marker compound 28, 30-bisnorhopane is also highly biodegraded but does exist in some Grosmont bitumen samples examined, supporting the notion that bitumens in the Devonian carbonates and the Cretaceous oil sands have a common origin. Based on the distribution characteristics of hopanes and tricyclics, several biodegradation parameters are identified and the samples are categorized into three distinct biodegradation stages. The data shows that the stage of biodegradation is likely most severe around stratigraphic boundaries and generally increases from southeast to northwest. Several recognized biodegradation parameters, such as 17α(H)-hopane/17α(H)-norhopane, are correlatable with the bitumen viscosity. Such parameters can be used as proxies for in situ viscosity, which is highly useful in aged samples (older than a few years) that have lost volatiles while in storage and thus no longer have the same viscosity as when retrieved from the reservoir.

Geophysical characterization of the Devonian Nisku Formation for the Wabamun area CO2 sequestration project (WASP), Alberta, Canada

Geophysical characterization of the Devonian Nisku Formation in the Wabamun area, Alberta, Canada for large-scale CO 2 sequestration project has been successful in revealing two primary groups of anomalies. The first group is interpreted to be due to contrasts in lithology of the Nisku Formation. This interpretation is supported by constraints provided by well control, seismic modeling and petrophysical data. The second group is interpreted to be footprints of geological discontinuities which are induced by dissolution and karsting in a geologic formation shallower in the stratigraphy. Even though there is no evidence to indicate that the integrity of the Nisku Formation or the overlying caprock has been compromised, such geologic discontinuities should be taken into consideration if supercritical CO 2 were to be injected into the Nisku Formation. The analysis has identified favorable low-impedance high-porosity locations that could be developed for a CO 2 injection site. Those locations exhibit a good correlation with relatively high porosity-permeability zones of the Nisku Formation on maps derived from wireline data and core analysis using petrophysical analysis. Finally, fluid replacement modelling was undertaken to predict the feasibility of time-lapse seismic monitoring for detecting an injected CO 2 plume. The results suggest that changes in seismic response will most likely be subtle and that the plume will probably be at the lower threshold of seismic detectability.

TOUGHREACT modeling of the fate of CO2 injected into a H2S containing saline aquifer: The example of the Wabamum Area Sequestration Project (WASP)

Abstract The Devonian Nisku formation in central Alberta is potentially a suitable aquifer for CO2 sequestration. As with many Devonian aged aquifers in the Western Canada Sedimentary Basin, it contains H2S from thermochemical sulfate reduction. In spite of this, the Devonian Nisku represents a potentially desirable location as it is at the correct depth to ensure that CO2 is in the supercritical phase, it has multiple impermeable and low permeability barriers and there is very little hydrocarbon production in the formation. This paper presents a modeling study of the injection phase of CO2 into a saline aquifer in the Devonian Nisku formation at Wabamum Lake in Central Alberta. The object of the study is to evaluate the differences and problems, if any, between injection into a brine with an ambient amount of dissolved H2S and without dissolved H2S. The simulation covers a CO2 injection period of 50 years at a rate of 1 Mt/year. A one dimensional, radial symmetric model was used with a uniform carbonate composition. The mineral composition was from the Upper Nisku formation and a water composition from a producing water well in the Nisku formation. The model found that injected CO2 was stored as ionically trapped bicarbonate in a region of varying widths, 300 m wide after 1 year of injection to 3000 m wide after 50 years of injection represents from 2% to 3% of injected CO2. Small amounts are also trapped as calcite and dolomite. The H2S in solution does exsolve as gas during injection but this result is inconclusive due to the small amount of dissolved H2S present in the ambient brine. Overall, there were no noticeable differences between the models with and without ambient H2S in the brine.

Reservoir Characterization for CO2Sequestration: Assessing the Potential of the Devonian Carbonate Nisku Formation of Central Alberta

The Wabamun Lake area of Central Alberta, Canada includes several large CO<sub>2<sub/> point source emitters, collectively producing more than 30 Mt annually. Previous studies established that deep saline aquifers beneath the Wabamun Lake area have good potential for the large-scale injection and storage of CO<sub>2<sub/>. This study reports on the characterization of the Devonian carbonate Nisku Formation for evaluation as a CO<sub>2<sub/> repository. Major challenges for characterization included sparse well and seismic data, poor quality flow tests, and few modern measurements. Wireline porosity measurements were present in only one-third of the wells, so porosity and flow capacity (permeability-thickness) were estimated using wireline electrical measurements. The Archie cementation factor appears to vary between 2 and 3, creating uncertainty when predicting porosity using the electrical measurements; however, high-porosity zones could be identified. The electrically-based flow capacity predictions showed more favorable values using a correlation with core than the relation based on drill stem and production tests. This behavior is expected, since the flow test flow capacities are less influenced by local occurrences of very permeable vuggy and moldic rocks. Facies distributions were modeled using both pixel and object methods. The object models, using dimensions obtained from satellite imaging of modern day environments, gave results that were more consistent with the geological understanding of the Nisku and showed greater large-scale connectivity than the pixel model. Predicted volumes show considerable storage capacity in the Nisku, but flow simulations suggest injection capacities are below an initial 20 Mt/year target using vertical wells. More elaborate well designs, including fracture stimulation or multi-lateral wells may allow this goal to be reached or surpassed.

The Wabamun Area Sequestration Project (WASP): A multidisciplinary study of gigaton scale CO2 storage in a deep saline carbonate aquifer

The Wabamun Area Sequestration Project (WASP) is a major integrated, multidisciplinary study investigating the potential for large-scale CO2 sequestration (>20 Mt/yr) in a deep saline aquifer in the Wabamun Lake area, southwest of Edmonton, Alberta, Canada. Four large coal-fired power plants in the region produce on the order of 30 Mt CO2/yr, with the goal being to inject 1 Gt of these emissions over 50 years. The WASP project establishes the viability of the Devonian Nisku Formation carbonate for large-scale injection. Storage capacity is thought to be between 0.2 and 0.3 Gt using conventional drilling and reservoir pressure management methods, while the injection potential may be increased to >0.4 Gt using more advanced strategies. Geostatistical manipulation of existing well log data, core-derived rock properties, and available seismic data allowed construction of static geologic models that were used for simulation of CO2 injection into the target formation. Important considerations include interactions of dissolved H2S in the aquifer brine with injected CO2; the geomechanics of the target formation and caprock seal; and the likely need for pressure management schemes to optimize injectivity without compromising seal integrity or large-scale aquifer behaviour. Future work should include more complete and up-to-date sampling of the caprock seal and entire injection formation interval; better aquifer brine samples for geochemical analysis; and in-situ test programs for assessing the geothermal effects on fracturing and the leakage rates through abandoned well bore cements and casings.

Characterization of solid bitumens originating from thermal chemical alteration and thermochemical sulfate reduction

Solid bitumen can arise from several reservoir processes acting on migrated petroleum. Insoluble solid organic residues can form by oxidative processes associated with thermochemical sulfate reduction (TSR) as well as by thermal chemical alteration (TCA) of petroleum. TCA may follow non-thermal processes, such as biodegradation and asphaltene precipitation, that produce viscous fluids enriched in polar compounds that are then altered into solid bitumens. It is difficult to distinguish solid bitumen formed by TCA from TSR since both processes occur under relatively high temperatures. The focus of the present work is to characterize solid bitumen samples associated with TSR- or TCA-processes using a combination of solid-state X-ray Photoelectron Spectroscopy (XPS), Sulfur X-ray Absorption Near Edge Structure Spectroscopy (S-XANES), and 13C NMR. Naturally occurring solid bitumens from three locations, Nisku Formation, Brazeau River area (TSR-related); La Barge Field, Madison Formation (TSR-related); and, the Alaskan North Slope, Brooks Range (TCA-related), are compared to solid bitumens generated in laboratory simulations of TSR and TCA. The chemical nature of solid bitumens with respect to organic nitrogen and sulfur can be understood in terms of (1) the nature of hydrocarbon precursor molecules, (2) the mode of sulfur incorporation, and (3) their concentration during thermal stress. TSR-solid bitumen is highly aromatic, sulfur-rich, and nitrogen-poor. These heteroatom distributions are attributed to the ability of TSR to incorporate copious amounts of inorganic sulfur (S/C atomic ratio >0.035) into aromatic structures and to initial low levels of nitrogen in the unaltered petroleum. In contrast, TCA-solid bitumen is derived from polar materials that are initially rich in sulfur and nitrogen. Aromaticity and nitrogen increase as thermal stress cleaves aliphatic moieties and condensation reactions take place. TCA-bitumens from the Brooks Range have <75% aromatic carbon. TCA-bitumens exposed to greater thermal stress can have a higher aromaticity, like that observed in TSR-bitumens. Organic sulfur in TCA-organic solids remains relatively constant with increasing maturation (S/C atomic ratio <0.035) due to offsetting preservation and H 2S elimination reactions. Although S-XANES and 13C NMR provide information needed to understand changes in structure and reactivity that occur in the formation of petroleum solids, in some cases XPS analysis is sufficient to determine whether a solid bitumen is formed by TCA or TSR.

Pervasive subsurface dolomitisation of the Devonian Nisku Formation, Canada — New insights from Reaction Transport Modeling

Pervasive subsurface dolomitisation of the Devonian Nisku Formation, Canada — New insights from Reaction Transport Modeling

DEVONIAN CARBONATES OF THE NIGEL PEAK AREA, ROCKY MOUNTAINS, CANADA: A FOSSIL PETROLEUM SYSTEM?

In this study we report on Devonian (Frasnian – Famennian) limestones and dolostones exposed near Nigel Peak in the Main Ranges of the Canadian Rocky Mountains. These carbonates are a proximal facies of the Southesk‐Cairn Carbonate Complex. The investigated strata are stratigraphically equivalent to the oil‐ and gas bearing Nisku Formation in the subsurface of the Western Canada Sedimentary Basin, about 300 km to the east. The rocks were investigated by polarisation and cathodoluminescence microscopy, total organic carbon analysis, Rock‐Eval pyrolysis, solid bitumen reflectance measurements, gas chromatography and fluid inclusion analysis.Thin section analyses showed that silt‐grade quartz and saddle dolomite increase upward from the base of the stratigraphic section, and that porosities are generally low. This is due to reduction of pore space due to early cementation and extensive dolomitization. Cathodoluminescence identified up to four generations of calcite cements. TOC values ranged from 0.2 to 2.4 %. Rock‐Eval pyrolysis of carbonate samples resulted in measurable S1 peaks but not S2 peaks, indicating that there was no residual petroleum generation potential. Organic petrographic analyses identified dispersed kerogen and migrabitumen, and calculated vitrinite reflectance values were around 4 % on average which implies peak temperatures of 234–262 °C (due to deep burial) or 309–352 °C (due to short term hydrothermal heating). Fluid inclusion data indicates at least one pulse of hot fluids with elevated homogenization temperatures of &gt; 300 °C, and this may explain the high thermal maturity of the studied rocks.

Geological and Hydrogeological Evaluation of the Nisku Q-Pool in Alberta, Canada, for H2S and/Or CO2Storage

The Brazeau Nisku Q-Pool in west-central Alberta is one of more than forty acid gas injection operations currently active in western Canada. The Nisku Q-Pool, mineralogically essentially dolomite and anhydrite, is a depleted sour gas reservoir in the Upper Devonian Nisku Formation. The Nisku is an oil, sweet and sour gas condensate play at depths ranging from about 2300 m in the northeast to more than 4200 m in the southwest, with a thickness of about 80 to 100 m. A unique feature of this play is that the hydrocarbons are contained in numerous closely spaced pools that have been essentially isolated hydrodynamically from one another since hydrocarbon migration and entrapment about 50-60 Ma ago, as shown by initial reservoir pressures and gas compositions. The hydrodynamic isolation renders these pools suitable for acid gas (H2 S + CO2 ) injection and/or carbon dioxide (CO2 ) sequestration. A thorough stratigraphic, diagenetic, mineralogical, and hydrogeological evaluation of the Nisku Formation suggests that the injected acid gas will remain in the structure that contains the Nisku Q-Pool on a geological time scale. In the highly unlikely case of migration out of the Q-Pool, the acid gas plume would disperse and dissolve in deep formation waters along the flow path. The only possibility for upward leakage of acid gas rapid enough to be of human concern is through wells that were improperly completed and/or are abandoned and are not monitored.

Evidence for Gloeocapsomorpha prisca in Late Devonian source rocks from Southern Alberta, Canada

Organic-rich intervals within the Late Devonian Camrose Member of southern Alberta, Canada show optical and chemical characteristics very similar to those of Ordovician samples whose organic matter is dominated by Gloeocapsomorpha prisca-derived alginite. This includes saturate fraction gas chromatograms dominated by n-alkanes with a pronounced odd carbon number up to C19, and much lower abundances of C19+n-alkanes, acyclic isoprenoids and biomarkers. Microscopy reveals these samples contain G. prisca-like alginite with a morphology that previously has been suggested for the growth of this organism under higher salinity conditions which is in agreement with the depositional environment of the Camrose Member. One unusual feature of the G. prisca-rich samples is the very high concentration of C21 and C23n-alkylnaphthalenes and n-alkylbenzenes in the aromatic fractions of their extracts. The origin of these compounds is not known but their occurrence could be related to the high concentrations of C21 and C23n-alkyl phenols that have been noted in pyrolysates of Estonian kukersites by previous workers. Other Camrose Member extracts show very different distributions that are more typical for carbonates deposited under anoxic, higher salinity conditions. Many oils that occur in Nisku Formation reservoirs in the Enchant-Hays field in southern Alberta show saturate fraction gas chromatograms and other evidence that indicate an important contribution to these oils from the G. prisca-rich intervals. These are thought to have a contribution from Camrose Member source rocks. Hence, caution should be used in only attributing G. prisca geochemical characteristics to Cambro-Ordovician oils as, on rare occasions, they can also occur in younger source rocks and their derived oils.

Bacterial and thermochemical sulfate reduction in diagenetic settings — old and new insights

The association of dissolved sulfate and hydrocarbons is thermodynamically unstable in virtually all diagenetic environments. Hence, redox-reactions occur, whereby sulfate is reduced by hydrocarbons either bacterially (bacterial sulfate reduction=BSR) or inorganically (thermochemical sulphate reduction=TSR). Their geologically and economically significant products are similar. Based on empirical evidence, BSR and TSR occur in two mutually exclusive thermal regimes, i.e. low-temperature and high-temperature diagenetic environments, respectively. BSR is common in diagenetic settings from 0 up to about 60–80°C. Above this temperature range, almost all sulfate-reducing microbes cease to metabolize. Those few types of hyperthermophilic microbes that can form H 2 S at higher temperatures appear to be very rare and do not normally occur and/or metabolize in geologic settings that are otherwise conducive to BSR. TSR appears to be common in geologic settings with temperatures of about 100–140°C, but in some settings temperatures of 160–180°C appear to be necessary. TSR does not have a sharply defined, generally valid minimum temperature because the onset and rate of TSR are governed by several factors that vary from place to place, i.e. the composition of the available organic reactants, kinetic inhibitors and/or catalysts, anhydrite dissolution rates, wettability, as well as migration and diffusion rates of the major reactants toward one another. BSR is geologically instantaneous in most geologic settings. Rates of TSR are much lower, but still geologically significant. TSR may form sour gas reservoirs and/or MVT deposits in several tens of thousands to a few million years in the temperature range of 100–140°C. BSR and TSR may be exothermic or endothermic, depending mainly on the presence or absence of specific organic reactants. However, if the reactions are exothermic, the amount of heat liberated is very small, and this heat usually dissipates quickly. Hence, heat anomalies found in association with TSR settings are normally not generated by TSR. The main organic reactants for BSR are organic acids and other products of aerobic or fermentative biodegradation. The main organic reactants for TSR are branched and n -alkanes, followed by cyclic and mono-aromatic species, in the gasoline range. Sulfate is derived almost invariably from the dissolution of gypsum and/or anhydrite, which may be primary or secondary deposits at or near the redox-reaction site(s). The products of BSR and TSR are similar, but their relative amounts vary widely and are determined by a number of locally variable factors, including availability of reactants, formation water chemistry, and wettability. The primary inorganic reaction products in both thermal regimes are H 2 S(HS − ) and HCO 3 − (CO 2 ). The presence of alkali earth metals often results in the formation of carbonates, particularly calcite and dolomite. Other carbonates, i.e. ankerite, siderite, witherite, strontianite, may form if the respective metal cations are available. Iron sulfides, galena, and sphalerite form as by-products of hydrogen sulfide generation, if the respective transition or base metals are present or transported to a BSR/TSR reaction site. Elemental sulfur may accumulate as a volumetrically significant net reaction product, usually when the system runs out of reactive hydrocarbons. Water may form as a by-product and might result in a local dilution of the formation waters at or near the reaction site. There are case studies of TSR, however, where no dilution of the formation water has occurred, indicating that the amount of water released during TSR was negligible. Porosity may be generated during TSR, but most case studies show that TSR does not usually result in a significant increase in porosity. TSR is likely to take place in fairly narrow reaction zones, where the irreducible water saturation in the hydrocarbon-containing pores is low. In one well known case, the Nisku Formation of Alberta, Canada, this zone is about 10–20 m thick. However, where the irreducible water saturation is high, TSR may take place throughout the entire hydrocarbon-containing pore volume. Solid bitumen may form as a by-product of both BSR and TSR. The mere presence of any of the above reaction products and by-products does not permit a distinction between BSR and TSR. However, a number of petrographic relationships and geochemical criteria can be used to discriminate these two processes. Specifically, most solid products of BSR and TSR, although similar in gross composition, can be distinguished from one another petrographically, i.e. most BSR (TSR) products form early (late) in the paragenesis and/or have distinctive crystal sizes, shapes, and/or reflectivity. However, there also are cases where BSR products formed relatively late diagenetically, e.g. in uplifted reservoirs after hydrocarbon migration. Gas chromatography, δ 13 C-, δ 34 S-analyses, and/or a combination thereof, offer the best distinguishing geochemical criteria.

Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin

Research Article| March 01, 2001 Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin* Martin G. Fowler; Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Lavern D. Stasiuk; Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Mark Hearn; Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Search for other works by this author on: GSW Google Scholar Mark Obermajer Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Search for other works by this author on: GSW Google Scholar Author and Article Information Martin G. Fowler Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Lavern D. Stasiuk Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Mark Hearn Shell Canada Ltd., 400 - 4 Avenue SW, Calgary, AB, T2P 2H5 Mark Obermajer Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB, T2L 2A7 Publisher: Canadian Society of Petroleum Geologists Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Online ISSN: 2368-0261 Print ISSN: 0007-4802 © The Society of Canadian Petroleum Geologists Bulletin of Canadian Petroleum Geology (2001) 49 (1): 117–148. https://doi.org/10.2113/49.1.117 Article history Received: 12 Sep 2000 Accepted: 16 Nov 2000 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Martin G. Fowler, Lavern D. Stasiuk, Mark Hearn, Mark Obermajer; Devonian hydrocarbon source rocks and their derived oils in the Western Canada Sedimentary Basin. Bulletin of Canadian Petroleum Geology 2001;; 49 (1): 117–148. doi: https://doi.org/10.2113/49.1.117 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search Abstract Devonian strata within the Western Canada Sedimentary Basin contain large reserves of oil and gas. These vast hydrocarbon reserves can be largely attributed to the occurrence of abundant mature, excellent to good quality Devonian source rocks. The Middle Devonian Elk Point Group contains several units with hydrocarbon potential including the Evie Formation in British Columbia, the Keg River Formation in northern Alberta, and the Winnipegosis Formation in east-central Alberta and southern Saskatchewan. Many of these are proven source rocks of oils occurring in Middle Devonian reservoirs. Elk Point Group potential source rocks contain a wide variety of organic matter types reflecting the diversity of their depositional environments. No hydrocarbons have been definitively linked to a Beaverhill Lake Group source rock but it is possible that such a unit is the source of Slave Point Formation reservoired oils in northwest Alberta. The Late Devonian Woodbend Group contains the Duvernay Formation, the most prolific Devonian source rock in the Alberta Basin. It is characterized by marine Type II/I organic matter with TOC contents up to 15% in immature samples and is the source of most oils in the Bashaw Reef Complex, the Rimbey-Meadowbrook Reef Trend, and in the Swan Hills Formation in Alberta. The stratigraphically equivalent Muskwa Formation in northern Alberta has a much lower hydrocarbon potential than the Duvernay Formation. Oils have been correlated to Winterburn Group source rocks within the Nisku Formation of east-central Alberta, Camrose Member/Nisku Formation of southern Alberta, and the time-equivalent Birdbear Formation of southeast Saskatchewan. Winterburn Group potential source rocks in central to southern Alberta can have high TOC contents (up to 15%) and contain Type I and Type II organic matter deposited in open marine to lagoonal palaeoenvironments. The Cynthia Member shale of the Nisku Formation in west-central Alberta, previously thought by some workers to be a source rock, is actually organic-lean. The underlying Bigoray Member is more organic-rich and may be a minor contributor to hydrocarbons in the West Pembina area. The Wabamun Group contains no regionally extensive potential source rocks. Almost all the oil generated from Devonian source rocks appears to have remained within Devonian-aged reservoirs and very little is biodegraded. In contrast, where Exshaw Formation sourced oil is found in Devonian reservoirs, such as in the Grosmont and Nisku formations in the vicinity of the Athabasca Mannville Group bitumen deposit (i.e. “Carbonate Trend”), it tends to be biodegraded. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.