Oil Sand Samples Research Articles

Matrix decomposition methods for accurate water saturation prediction in Canadian oil-sands by LF-NMR T2 measurements

This article presents a novel method for quantifying water saturation in oil-sand reservoirs by employing 1D low-field nuclear magnetic resonance (LF-NMR) spin-spin relaxation and bulk density measurements as indicators of pore volume variations. One of the challenges in accurately determining the volumes of bitumen and water in oil-sands is the effective separation of their overlapping T2 signals, attributed to similar spin-spin relaxation decay times and diffusive coupling. Conventional methods require deconvolution of T2 peaks and or experimentation to determine T2 cutoff values, differentiating between bitumen and water signals, notably capillary and clay-bound water. In contrast, our approach predicts the proportion of water by utilizing matrix decomposition methods to compress the T2 relaxation distribution and extract significant components. These components subsequently train the regression model, facilitating the accurate estimation of relative water saturation percentages.The NMR dataset was obtained by benchtop LF-NMR T2 measurements from 82 oil-sand samples, with preserved bitumen and water saturations at both reservoir and ambient temperatures (6 °C and 25 °C), yielding 164 observations. We examined four matrix decomposition methods, including principal component analysis, its variation integrating a kernel function, canonical correlation analysis, and partial least squares regression. X-ray CT measurements and Dean-Stark extraction ascertained the respective sample bulk densities and fluid-solid volume proportions.The PCA model prediction statistics (RMSE = 0.86%, R2 = 0.84), indicate its application can be extended for saturation prediction from NMR and bulk density well logs. Moreover, we underscore the importance of incorporating bulk density measurements and establish the statistical and physical correlations between these measurements and NMR T2 relaxation, providing insights into the approach's efficacy and causality.

Geochemical evidence for Alberta Oil Sands contamination in sediments remote to known oil sands deposits in Alberta, Canada

Oil spills and natural oil seeps are sources of petrogenic hydrocarbons in soils and sediments. To determine the source of hydrocarbon contamination in the environment the geochemical signature of the contaminant needs to be characterised. Here, we present biomarker and other molecular marker diagnostic ratios of Alberta Oil Sands using gas chromatography-mass spectrometry to characterise the deposits and detect their incorporation in surficial sediments. Diagnostic ratios of steranes, terpanes, and aromatic steroids (e.g. C27, C28, and C29 regular sterane abundance, Gammacerane Index, Ts/Tm, TAS/(TAS + MAS), and MPI-2) were measured in samples of Alberta Oil Sands providing a set of criteria for their identification. Seven surficial sediment samples from central and southeast Alberta were then analysed using these criteria to detect Alberta Oil Sands contamination and other petrogenic and pyrogenic source inputs. Geochemical signatures consistent with Alberta Oil Sands hydrocarbons were identified in surficial sediments in Lamont County and glacial sediments from a moraine in Beaver County. Both sites are in Central Alberta, ∼300 km south of any oil sands extraction sites and natural exposures in northern Alberta, indicating long-distance sediment transport processes mobilised the deposits. These results show that the oil sands have been eroded and transported beyond the boundaries of their current known limits. This is important for understanding sediment transport processes as well as for remediation and reclamation purposes.

Application of XGBoost model for in-situ water saturation determination in Canadian oil-sands by LF-NMR and density data

Water saturation determination is among the most challenging tasks in petrophysical well-logging, which directly impacts the decision-making process in hydrocarbon exploration and production. Low-field nuclear magnetic resonance (LF-NMR) measurements can provide reliable evaluation. However, quantification of oil and water volumes is problematic when their NMR signals are not distinct. To overcome this, we developed two machine learning frameworks for predicting relative water content in oil-sand samples using LF-NMR spin–spin (T2) relaxation and bulk density data to derive a model based on Extreme Gradient Boosting. The first one facilitates feature engineering based on empirical knowledge from the T2 relaxation distribution analysis domain and mutual information feature extraction technique, while the second model considers whole samples’ NMR T2-relaxation distribution. The NMR T2 distributions were obtained for 82 Canadian oil-sands samples at ambient and reservoir temperatures (164 data points). The true water content was determined by Dean-Stark extraction. The statistical scores confirm the strong generalization ability of the feature engineering LF-NMR model in predicting relative water content by Dean-Stark—root-mean-square error of 0.67% and mean-absolute error of 0.53% (R2 = 0.90). Results indicate that this approach can be extended for the improved in-situ water saturation evaluation by LF-NMR and bulk density measurements.

Metal–Metal Correlation of Biodegraded Crude Oil and Associated Economic Crops from the Eastern Dahomey Basin, Nigeria

The presence of heavy metals in plants from oil sand deposits may reflect mineralization resulting from petroleum biodegradation. Petroleum composition and heavy metal analyses were performed using thermal desorption gas chromatography and atomic absorption spectrophotometry on oil sand and plant root samples from the same localities in the Dahomey Basin. The results from the oil sand showed mainly heavy-end hydrocarbon components, humps of unresolved complex mixtures (UCM), absences of C6-C12 hydrocarbon chains, pristane, and phytane, indicating severe biodegradation. In addition, they showed varying concentrations of vanadium (2.699–7.708 ppm), nickel (4.005–11.716 ppm), chromium (1.686–5.733 ppm), cobalt (0.953–3.223 ppm), lead (0.649–0.978 ppm), and cadmium (0.188–0.461 ppm). Furthermore, these heavy metals were present in Citrus, Theobroma Cacao, Elaeis guineensis, and Cola. The chromium, nickel, vanadium, lead, cobalt, and cadmium concentrations in the Citrus were 7.475, 4.981, 0.551, 0.001, 0.806, and 0.177 ppm, respectively. For the Theobroma Cacao, the concentrations of chromium, nickel, vanadium, lead, cobalt, and cadmium were 7.095, 16.697, 2.151, 0.023, 3.942, and 0.254 ppm. Elaeis guineensis also showed the presence of chromium (32.685 ppm), nickel (32.423 ppm), vanadium (11.983 ppm), lead (0.190 ppm), cobalt (4.425 ppm), and cadmium (0.262 ppm). The amounts of chromium, nickel, vanadium, lead, cobalt, and cadmium in the Cola were 9.687, 9.157, 0.779, 0.037, 0.695, and 0.023 ppm. The World Health Organization’s (WHO) safe and permissible limits for Cd (0.003 ppm), Cr (0.1 ppm), Ni (0.05 ppm), and Pb (0.1 ppm) in agricultural soils were all exceeded in the oil sand. The presence of these metals in the oil sands and their uptake by the plants could potentially be toxic, resulting in high mortality. The metal–metal correlation of the plant’s rootsto the oil sand indicates the nonanthropogenic origin of the heavy metals, which leads to the conclusion that their source is related to the hydrocarbon accumulation in the Afowo sand.

Study on a Strain of Lysinibacillus sp. with the Potential to Improve the Quality of Oil Sands

A strain of Lysinibacillus sp., named as Y316, can degrade heavy fractions such as resins and asphaltenes in oil sand. We used Y316 to degrade oil sand samples for 35 days. After bacterial degradation, the oil sand degradation efficiency was 5.88%, while the degradation efficiency of the control group was only 0.29% under the same conditions. Compared with the control group, the saturated content of oil sand in the degradation group increased from 9.56 to 14.39%. After degradation, the resin and asphaltene fractions decreased by 5.34 and 4.77%, respectively. The results of the vaporizable fraction analysis also confirmed the degradation of heavy fractions and the formation of light fractions. After 35 days of degradation, the vaporizable fractions of saturates increased by 3.76 times. The results indicate that Y316 has great significance for improving the quality of oil sands and assisting in oil sand exploitation.

Temperature-Dependent Wave Velocities of Heavy Oil-Saturated Rocks

Abstract Understanding the dependence of the rock properties on temperature is essential when dealing with heavy oil reservoirs. Reported rock physics models can hardly capture the effect of temperature on wave velocities. We propose a dual-porosity temperature-dependent model based on the coherent potential approximation, combining temperature- and frequency-dependent empirical equations for pore fluids with the David-Zimmerman model. The Maxwell model is adopted to obtain the complex shear modulus as a function of temperature and frequency. To verify the validity of the model, a glycerol-saturated tight sandstone and three heavy oil sand samples are considered. The comparison between the predicted and measured wave velocities shows that the model can quantitatively describe the behavior as a function of temperature. We find that there is a viscosity threshold (liquid point), where the P- and S-wave velocity variation trends change, while the porosity has no effect.

Geochemical Characterizations of Source and Depositional Environment of Hydrocarbons in the Lake Albert Rift Basin

AbstractDespite the upsurge in hydrocarbon exploration in the Lake Albert Rift Basin (LARB) over the past three decades, systematic characterization of hydrocarbon compositions remains lacking, leading to uncertainties in source rock and oil generation determination. We characterized crude oil compositions and oil sand samples in the northern and southern subbasins of LARB. The relative abundance of normal and branched linear alkanes, hopanes, steranes, and aromatic hydrocarbon suggest that northern and southern hydrocarbons were deposited in anoxic to suboxic lacustrine environments and share similar biological source compositions (i.e., a mixture of plants and aquatic algae and bacteria). Relative to southern samples, northern samples show more negative δ13C values for oils, saturates and aromatics, indicating longer migration paths, and exhibit higher MPI‐1, DNR‐1 and 4‐/1‐MDBT ratios, indicating higher maturity. Between the two possible sets of source rocks (upper Miocene and Jurassic strata), the positive δ13C values of saturated hydrocarbons (average = –20.5‰) suggest that the upper Miocene lacustrine shale is the most likely candidate. Oleanane index (<5% in our samples) does not exclude either source rock possibility, and C28/C29 regular sterane (average = 0.63) may be biased by high terrestrial inputs in a lacustrine setting. Together, our data show that northern and southern oils originate from the same source rocks but different oil kitchens. Given the similar geochemical characteristics of southern and northern oils, previous exploration successes in the northern subbasin likely suggest similar potential in the southern sector, while other elements influencing exploration success must be also evaluated.

Monitoring of steam chamber in steam-assisted gravity drainage based on the temperature sensitivity of oil sand

Thermosensitivity experiments and simulation calculations were conducted on typical oil sand core samples from Kinosis, Canada to predict the steam chamber development with time-lapse seismic data during the steam-assisted gravity drainage (SAGD). Using an ultrasonic base made of polyether ether ketone resin instead of titanium alloy can improve the signal energy and signal-to-noise ratio and get clear first arrival; with the rise of temperature, heavy oil changes from glass state (at –34.4 °C), to quasi-solid state, and to liquid state (at 49.0 °C) gradually; the quasi-solid heavy oil has significant frequency dispersion. For the sand sample with high oil saturation, its elastic property depends mainly on the nature of the heavy oil, while for the sand sample with low oil saturation, the elastic property depends on the stiffness of the rock matrix. The elastic property of the oil sand is sensitive to temperature noticeably, when the temperature increases from 10 °C to 175 °C, the oil sand samples decrease in compressional and shear wave velocities significantly. Based on the experimental data, the quantitative relationship between the compressional wave impedance of the oil sand and temperature was worked out, and the temperature variation of the steam chamber in the study area was predicted by time-lapse seismic inversion.

Ferrocene addition for suppression of hydrogen sulfide formation during thermal recovery of oil sand bitumen

The occurrence of H2S during thermal recovery production becomes one of the biggest challenges. While various industrial processes can remove H2S at the surface, to prevent the formation of H2S in reservoir is much less successful. Ferrocene was chosen as the likely target reagent after a review of iron compound volatility and environmental considerations. To evaluate this, closed system gold tube pyrolysis experiments were conducted on an Athabasca oil sand at 350–650 °C to examine gas compositions with and without ferrocene addition. Slightly higher hydrocarbon gas yields have been observed from samples with ferrocene addition likely caused by ferrocene decomposition. Yields of carbon dioxide (CO2) are higher in plain oil sand samples before 550 °C but the trend was reversed afterwards with more CO2 being generated from ferrocene addition ones. H2S yields in samples without ferrocene increase from background value at 350 °C to the highest amount at 450 °C then disappear above 625 °C. Thermal decomposition of organosulfur compounds is supposed to be the main route for the occurrence of H2S in the sulfur-rich bitumen pyrolysis. Ferrocene is proved to be powerful H2S removal reagent as no H2S can be detected from ferrocene addition samples. The reactions of ferrocene with H2S may form iron sulfides, cyclopentadiene and hydrogen. Complete, rapid, and predictable reactions and inert reaction products make ferrocene as an ideal in situ H2S scavenger, while the potential for the deposition of metal sulfides may reduce the permeability. Ferrocene is widely available for industry, however, the unit cost has not been assessed in this study.

Organic geochemical characteristics and comparison of the source rocks and the severely biodegradable oil sands around Karamay, China

For the sake of explaining the organic geochemical characteristics of the hydrocarbon source rocks (SRs) around Karamay, such as thermal maturity (TM) (evidences from the temperature of maximum pyrolysis yield (Tmax), the Carbon Preference Index (CPI) and Odd to Even Preference (OEP) values, the C30 M/H versus Tm/Ts, the C29 ββ/(ββ + αα) versus C29 20 S/(20 S + 20 R)), hydrocarbon potential (HP) (evidences from total organic carbon (TOC) and rock pyrolysis (RP)), organic matter (OM) source input (evidences from n-Alkane distribution, the relative quantity of C27-C28-C29 steranes, the (C19 + C20)/C23 tricyclic terpane (TT), and the Terrigenous/aquatic ratio (TAR)) as well as paleoenvironment (evidences from the pristane/phytane (Pr/Ph) and the Gammacerane index), and in order to analyze the biodegradation degree and source of oil sand (OS) oil, 55 core samples of SRs in all were selected to measure TOC and RP. 14 core samples of SRs and 3 OS samples were selected for gas chromatography–mass spectrometry (GC-MS) analysis. 11 core samples of SRs and 3 OS samples were used for organic carbon isotope (OCI) analysis. The results indicate that except the SR from Fengcheng formation (P1 f) which is in the stage of high or over evolution, the other SRs are in mature stage. OM type of Carboniferous (C) SRs are type Ⅱ kerogen, with the largest abundance. OM type of the SRs in Wuerhe formation (P2 w) and Jiamuhe formation (P1 j) are type Ⅲ kerogen with good and medium OM abundances. Almost all SRs were formed in the reduction environment of high salinity, and the main OM source input is the lower aquatic plants. Karamay formation (T2 k) and Badaowan formation (J1 b) oil sands (OSs) around Karamay have undergone serious biodegradation. It is suggested that OS oil are mainly from P1 f SRs (evidences from the tricyclic terpanes (TT), triarysteranes, pregnane, homopregnane and OCI).

Anaerobic microbial communities and their potential for bioenergy production in heavily biodegraded petroleum reservoirs.

Most of the oil in low temperature, non-uplifted reservoirs is biodegraded due to millions of years of microbial activity, including via methanogenesis from crude oil. To evaluate stimulating additional methanogenesis in already heavily biodegraded oil reservoirs, oil sands samples were amended with nutrients and electron acceptors, but oil sands bitumen was the only organic substrate. Methane production was monitored for over 3000 days. Methanogenesis was observed in duplicate microcosms that were unamended, amended with sulfate or that were initially oxic, however methanogenesis was not observed in nitrate-amended controls. The highest rate of methane production was 0.15 μmol CH4 g-1 oil d-1 , orders of magnitude lower than other reports of methanogenesis from lighter crude oils. Methanogenic Archaea and several potential syntrophic bacterial partners were detected following the incubations. GC-MS and FTICR-MS revealed no significant bitumen alteration for any specific compound or compound class, suggesting that the very slow methanogenesis observed was coupled to bitumen biodegradation in an unspecific manner. After 3000 days, methanogenic communities were amended with benzoate resulting in methanogenesis rates that were 110-fold greater. This suggests that oil-to-methane conversion is limited by the recalcitrant nature of oil sands bitumen, not the microbial communities resident in heavy oil reservoirs.

Evaluation of source rock potential and hydrocarbon composition of oil sand and associated clay deposits from the Eastern Dahomey Basin, Nigeria

Oil sands are classified as unconventional hydrocarbon plays and are being exploited to augment global energy needs. Nigeria has the largest conventional oil industry in Africa, but is also endowed with abundant oil sand deposits found within the Afowo Formation of the Eastern Dahomey Basin. In this study, outcrop samples of clay, oil sand, and bitumen seepage from a forestry reserve (J4) in Ogun State, South Western Nigeria were evaluated for organic matter maturity and hydrocarbon composition. Pyrolysis results for the clay indicate that the total organic carbon ranges from 5.95 to 18.46 wt % with a maturation temperature (Tmax) within the range of 417–426 °C. A complementary gas chromatography (GC) analysis of the free hydrocarbons in the clay reveals that both light and heavy hydrocarbon components are present. In contrast, oil sand and bitumen contain mostly heavy end hydrocarbon components with hydrocarbon chains C6–C12 missing, confirming oil biodegradation. This study demonstrates that these oil sands and clays represent viable exploration targets. With vast oil sand deposits in the Eastern Dahomey Basin, exploration and exploitation of this resource will open new frontiers to increase Nigeria's hydrocarbon production.

Radio Frequency Heating combined with Solvent Extraction- A method for oil recovery from surface oil sands

Trinidad has oil sands resources of about 2 billion barrels of oil on land. However, due to the relatively small extent and surface location (about 10,000 acres and with depths varying from surface to less than 500 feet), large scale surface mining and in-situ methods such as SAGD and VAPEX that are applied to recover oil from Canadian oil sands, are not practical. From experimental and simulation studies conducted, a new method was developed to commercially recover oil from Trinidad's surface oil sands.The open literature shows Radio Frequency Heating (RFH) to be more practical than electrical resistive heating (ERH) for surface oil sands. RFH is cheaper, quicker and heating is uniform and deeper than ERH, with oil recoveries ranging from 50 to 80%. Experimental studies show the viscosity of Trinidad oil sand oil to be greater than 10,000 cp and temperatures greater than 170 °C are required for the oil to flow. The power requirement for applying RFH at this temperature is greater than 25 kW (kW) and very costly. In addition, vaporisation of oil components occurs at these high temperatures, which is not environmentally safe for surface application.This new oil recovery method uses RFH at low power (1 kW) with a locally extracted organic solvent. The RFH system designed and assembled consists of an RFH chamber, signal generator and low power amplifier (1 kW). Samples of oil sands were heated in the chamber to 100 °C using a low frequency of 11.5 MHz and a citrus oil extracted in house was injected. Bitumen recoveries in the range 60–70% were achieved after three cycles of solvent injection and RFH.Experimental studies conducted show that Trinidad oil sands have a clay content in the range of 10–20%, are water wetting with a water saturation in the range 10–20% and have relative permittivities in the range 38–100. From this data, a new mathematical correlation was developed to obtain permittivities of oil sands which can be used with industry software to simulate oil recovery by RFH. Simulation studies show that for a 70% recovery from three cycles, eight gallons of solvent per cycle are required with RFH at a temperature of 100 °C.The data from the experimental and simulation studies show that with a heating cost of 2.50 USD to produce a barrel of oil, a solvent cost of 16 USD/barrel and with drilling, equipment and operational costs, and this method is viable at an oil price over 25 USD/barrel. The low cost and minimal environmental impact of this new method makes it very attractive for oil extraction from surface oil sands.

Hydrocarbon Recovery From Oil Sands by Cyclic Surfactant Solubilization in Single-Phase Microemulsions

Extra heavy crude oil (bitumen) reserves represent a significant part of the energy resources found all over the world. In Canada, the “oil sands” deposits are typically unconsolidated, water-wet media where current methods of recovery, such as open pit mining, steam-assisted gravity drainage (SAGD), vapor extraction, cold heavy oil production with sand, etc., are controversial due to adverse effect on environment. Chemical enhanced oil recovery (cEOR) techniques have been applied as alternatives but have limited success and contradictory results. An alternative method is described in this paper, which relies on the application of single-phase microemulsion to achieve extremely high solubilization. The produced microemulsion will be less viscous than oil, eliminating the need for solvent addition. Produced microemulsion can be separated to recover surfactant for re-injection. The work in this paper discusses phase behavior experiments and a flow experiment to prove the concept that single-phase microemulsions could be used to recover extra-heavy oils. Phase behavior experiments showed that the mixture of alcohol propoxysulfate, sodium dioctyl sulfosuccinate, sodium carbonate, and tri-ethylene glycol monobutyl ether results in single-phase microemulsion with extra-heavy crude. A flow experiment conducted with the same composition produced only single-phase microemulsion leading to 74% recovery of the original oil in place from a synthetic oil sand. Future experiments will be focused on optimizing the formulation and testing with actual oil sands samples.

Study of the Relationship Between the Oil Content of Oil Sands and Spectral Reflectance Based on Spectral Derivatives

The oil content of oil sands is an important factor in oil sand resource evaluation. In this study, we use spectral reflectance to study the oil content parameter. The spectrograph can be used to determine the target spectral reflectance directly, using a fiber-optic probe, without destroying samples or using chemical reagents, which has the advantage of quick measurement and analysis. This paper documents the acquisition of hyperspectral data in the range of 350–2500 nm through spectrometry of oil sand samples. We process the original reflectivity data using the first-order and second-order differentials and then calculate and analyze the correlation coefficient with reflectivity of oil sands and the first and second derivatives of reflectance. Based on the characteristics of the correlation coefficient graphs, we determine the wave bands sensitive to oil content and verify that using hyperspectral data in the study of oil content is feasible.

Effect of Temperature on the Strength Parameters at the Plastic Domain for Unconsolidated Sandstones

Heavy and extra heavy oil reservoirs are subjected to high temperatures during thermal recovery processes like SAGD and CSS. In-situ temperature state changes throughout these operations may generate variations in the mechanical properties or strength parameters of the rock such as Young and Bulk’s modulus, internal friction angle, cohesion and dilation angle. This paper presents results about the variation of the elastic modulus and mechanical properties, in both elastic and plastic region due to changes in temperature and effective confining stress for reconstituted samples of Colombian unconsolidated sands. In order to study these changes, several drained triaxial tests are performed in a range of temperature between 50 and 230 °C and a range of effective confining stress between 0.4 and 8.2 MPa, these tests are carried out on reconstituted samples of oil sands recovered in an outcrop in the Magdalena middle valley of Colombia. The experimental results are analyzed with an analytical model based on the constitutive model of Mohr–Coulomb. The analysis is divided in two ways: First, the elastic region is analyzed calculating the variation of the elastic modulus (Young and bulk’s modulus) and the mechanical parameters (cohesion and internal friction angle) with temperature and effective confining stress, these calculus are done in the linear zone of the stress–strain curve. Then, the plastic region is analyzed using Mohr–Coulomb constitutive model with a non-associative flow rule in order to represent in a better way the dilatant/contractive behavior of the material, from this analysis is possible to obtain the behavior of the mechanical properties during plastic strains. The stress–strain curves obtained from the triaxial compression tests show that for the highest and medium effective confining stress (8.2 and 4.0 MPa), there is a hardening strain behavior after the yielding point that implies a loose sand behavior under confining conditions. Meanwhile, for lowest effective confining stress (0.4 MPa) the samples show a softening strain, a typical behavior for dense sands under confining conditions.

Oil sand pyrolysis: Evolution of volatiles and contributions from mineral, bitumen, maltene, and SARA fractions

In order to investigate the pyrolysis behavior through the volatile evolution, pyrolyzer-evolved gas analysis-mass spectrometry and thermogravimetric analysis-mass spectrometry were adopted for in situ analysis and comparison the pyrolytic volatiles derived from two different oil sands as well as their mineral, bitumen, maltene and SARA fractions. For both oil sands, the weight loss and volatile release during the oil-producing process exhibited two stages: a devolatilization stage (<350 °C) and a thermal-cracking stage (350–600 °C). These two stages afforded different volatile yields and displayed distinct activation energy distributions. Additionally, heart-cut analysis indicated that the volatiles were in disparate compositions at each stage. The volatile evolution of the oil sand bitumen, maltene, and SARA fractions revealed individual contributions on volatile release with increasing pyrolysis temperature. Specifically, volatiles in the devolatilization stage predominantly originated from the saturates in maltene. These resulted in a significant amount of polycyclic biomarkers and contributed toward the release of higher-molecular-weight substances over a temperature range of 200–350 °C. The thermal-cracking stage was the main stage in which most of the gaseous and light pyrolytic products, including amounts of alkanes and olefins, were generated. These compounds mostly originated from cracking of resin and asphaltenes. The aromatic fraction was observed that released volatiles in both stages. Thus, due to the disparity in temperature region for volatile release, the volatile yields during the different stages of the process were mainly determined from the organic constituents of the oil sand. Notably, the volatile compositions predominantly correlated to the original organic structures. Moreover, the minerals exhibited little influence during the oil-producing stage of the two oil sand samples under the tested heating conditions. However, the presence of interactions between these organic sub-fractions during oil sand pyrolysis is suggested.

Measurement of radioactivity level of sand fraction of Nigerian oil sands for environmental impact assessment

ABSTRACTThe radioactivity level of the sand fraction of Nigerian oil sands collected from four different locations, namely Ilubirin, Olowo-Irele, Loda, and Orisunbare, Ondo State, Nigeria, were identified and quantified with the view to assess its likely environmental and health impact of the exploration, exploitation, processing, and transportation of the fossil fuel. Soxhlet extractor was used to extract bitumen from the oil sand samples using toluene as extracting solvent. The sand fraction as left-over collected from the thimble after exhaustive extraction was dried in the oven at 70°C for 8 h to remove trace water and extracting solvent. A survey of radioactivity content and associated radiological risks was carried out on the sand fraction samples by means of a well-calibrated gamma-ray spectrometer containing Na-I (Tl) detector. The mean specific activities of 40K, 232Th, and 238U present in the analyzed sand fraction samples were 3131.17 ± 5.71, 147.90 ± 10.85, and 96.28 ± 2.59 Bq/kg, respectively. The results obtained for the absorbed dose rate (AD), annual effective dose rate (AEDR), internal hazard index (Hin), external hazard index (Hex), annual gonadal equivalent dose (AGED), and the representative levels index (Iγr) were 264.380 nGy/h, 0.324 mSv/year, 1.461 Bq/kg, 1.481 Bq/kg, 1903.073 µSvy–1, and 2.185, respectively. The AD values were higher than the population weighted average (60 nGy/h) recommended by UNSCEAR. The Hex and Hin values were above unity for the studied samples except from Ilubirin. The results follow similar trend for all the radiological parameters. The AGED values were higher than the world average (300 µSvy–1) set by UNSCEAR. The average lifetime cancer of mortality risk due to 40K, 232Th, and 238U was 2.09 × 10–3, 4.18 × 10–8, and 1.84 × 10–6, respectively, while that morbidity risks due to 40K, 232Th, and 238U were 3.07 × 10–3, 6.21 × 10–8, and 2.70 × 10–6, respectively. Radiological assessment however indicated that long-term exposure may pose an intrinsic health hazard.

Study on vacuum pyrolysis of oil sands by comparison with retorting and nitrogen sweeping pyrolysis

Vacuum pyrolysis is a promising technology for the production of fossil fuels from oil sands. In this study, vacuum pyrolysis was compared with retorting and nitrogen sweeping pyrolysis based on the yields and the properties of the pyrolysis products. In the pyrolysis experiments, the samples of oil sands were heated to the final reaction temperature under varying heating rates and varying vacuum pressures. It was found that the effect of the reactor heating rate on the liquid oil yield of the pyrolysis reactions became less significant as the pressure was decreased below atmospheric level, to the point that the liquid yield of complete vacuum pyrolysis (0MPa) was independent of the variation in heating rate. Longer vapor residence times lead to higher gas and coke yields and lower liquid yields. The coupling of retorting and vacuum pyrolysis was proposed and investigated, with the conclusion that vacuum can be utilized after the reactor reaches 500°C with little sacrifice of the liquid product yield that can be produced by using vacuum only. Elemental analysis and the analysis of the distribution of saturates, aromatics, resins and asphaltenes (SARA) were carried out to characterize the differences in the composition of the pyrolysis liquid products. Simulated distillation was conducted to analyze the boiling point distribution of the initial bitumen and the pyrolysis oil products. Significant differences in the distribution of SARA fractions were observed between samples obtained from solvent extraction process and those from pyrolysis.

Predicting the abundance of clays and quartz in oil sands using hyperspectral measurements

Clay minerals play a crucial role in the processability of oil sands ores and in the management of tailings. An increase in fine content generally leads to a decrease in both bitumen recovery performance and tailings settling rate. It is thus important to identify clay types and their abundance in oil sands ores and tailings. This study made use of oil sands samples characterized for quantitative mineralogy by x-ray diffraction, to gain an understanding of changes in the reflectance spectra of oil sands. The sample suite included bitumen-removed oil sands ore samples and their different fine size fractions. Spectral metrics applicable to the prediction of quartz and clay contents in oil sands were then derived with a focus on metrics correlating with sample content in total 2:1 clays (total of illite and illite-smectite) and kaolinite. Metrics in the shortwave infrared (SWIR) and longwave infrared (LWIR) were found to correlate with mineral contents. The best predictions of clays and quartz were achieved using LWIR metrics (R2>0.89). Results also demonstrated the applicability of LWIR metrics in the prediction of kaolinite and total 2:1 clays.