Oil Sand Reservoirs Research Articles

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Temperature distribution considering the film-wise condensation and its impact on multi-stage oil production during the co-injection of steam-CO2

The co-injection of steam and CO2 into oil sands reservoirs has proved to be one of the most efficient and environmentally friendly methods to produce bitumen. Nevertheless, the condensation mechanism of steam in the reservoir is film-wise condensation under the effect of CO2, which reduces the heat transfer efficiency of steam. To obtain accurate oil production during the co-injection of steam-CO2, it is critical to predict the temperature distribution considering the film-wise condensation and clear its impact on oil production. In this study, laboratory experiments with different injectors were conducted to clear the effect of film-wise condensation on temperature distribution in the formation. Then, a mathematical model considering film-wise condensation was established to predict the temperature distribution and oil production, compared with the measured experiment result and multi-stage oil production from field data. Finally, the effect of temperature distribution on multi-stage oil production was analyzed through different injection volumes. The results indicated that the impact of film-wise condensation inhibits the development of the steam zone(Ts) but explicitly expands the hot water zone(Ts ∼ Tr). Moreover, the different injection components affect film-wise condensation, and CO2 has a more pronounced effect, whereas steam has little impact on the hot water zone despite its significant effect on steam zone expansion by weakening the film-wise condensation. Furthermore, the oil production exhibits the multi-stage characteristic controlled by different heating zones(the steam zone and the hot water zone), such that the steam zone contributes to higher oil production in the rising stage, and a larger hot water zone induces a longer life of the rising stage and the stable stage.

Impact of Reservoir Heterogeneity on Bitumen Content in the Mackay River Oil Sands, Athabasca (Canada)

AbstractThe Lower Cretaceous Manville Group of Upper McMurray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high‐quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper McMurray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar (TB) or tidal channel (TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar (SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat (MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.

Thermal analysis of V-pad thermocouple used on once-through steam generator tubes

Once-Through Steam Generators (OTSGs) are used in the oil sands industry to produce steam, which is injected into oil sands reservoirs to produce bitumen. OTSGs consist of a combustion zone where natural gas is combusted to generate thermal energy, which boils water within tubes that pass through the OTSG. In a typical OTSG, the temperature at the external wall of the tubes can reach as high as 500 °C, or even higher. Temperature measurement of the tube wall is critical for safe operation and this can be determined by using thermocouples. However, the placement of the thermocouple and its shield to protect it on the tube outer wall interferes with heat transfer and, thus, the measured temperature from the thermocouple may not be equal to the bare tube (no thermocouple) temperature. Here, we examine how the placement of a thermocouple on a tube wall in an OTSG affects the tube wall temperature by using finite-element-based heat transfer modelling. Depending on the foulant thickness, and the placement of the thermocouple, the local tube wall temperature increases by 45 to 55 °C. The results show that using thermocouples with shields can yield a temperature measurement error of order of 15–30 °C above the actual bare tube temperature. The results provide a basis for correcting the thermocouple/shield derived value to the actual temperature of the tube wall.

Optimization of the SAGD Preheating for the Athabasca Oil Sands Reservoir with a Water Transition Zone

Optimization of the SAGD Preheating for the Athabasca Oil Sands Reservoir with a Water Transition Zone

CORRIGENDUM to “Optimization of Fast-steam-assisted gravity drainage for the energy-efficient operations at a heterogeneous oil-sands reservoir”

CORRIGENDUM to “Optimization of Fast-steam-assisted gravity drainage for the energy-efficient operations at a heterogeneous oil-sands reservoir”

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.

Sequentially Coupled Thermal-Hydraulic-Mechanical Simulation for Geomechanical Assessments of Caprock Integrity in SAGD

Oil sand reservoirs and caprock undergo deformations triggered by pore pressure increases and thermal induced stresses during the steam-assisted-gravity-drainage (SAGD) processes. Geomechanical assessments are mandated by energy regulators to evaluate the caprock integrity and ensure the safe SAGD operations. Commercial reservoir simulation packages started to incorporate geomechanical effects when predicting flow response; however, these geomechanical modules are not able to correctly model the plastic deformations caused by thermal-hydraulic-mechanical (THM) interactions, which has a first order effect on predicting steam chamber propagation and evaluating caprock integrity.
 An integrated coupled THM modeling methodology is proposed here to improve the modeling of reservoir deformations and caprock integrity in a heterogeneous oil sand reservoir with interbedded shale barriers. The pressure and temperature front are found to propagate at different speed and that dominate the elastic and plastic deformations caused by changes of shear and mean effective stress. Therefore, four stages are divided in the SAGD process that can be interpretations of changes in stress paths including buildup of pore pressure, generation and dissipation of thermal induced stresses. The response surfaces of minimum factor of safety (FOS) are introduced and computed to provide a conservative estimate for caprock integrity during SAGD of a heterogeneous reservoir with multiple layers of caprocks in Athabasca oil sands. 

Application of Finite Element Technique: A Review Study

The finite element approach is used to solve a variety of difficulties, including well bore stability, fluid flow production and injection wells, mechanical issues and others. Geomechanics is a term that includes a number of important aspects in the petroleum industry, such as studying the changes that can be occur in oil reservoirs and geological structures, and providing a picture of oil well stability during drilling. The current review study concerned about the advancements in the application of the finite element method (FEM) in the geomechanical field over a course of century. Firstly, the study presented the early advancements of this method by development the structural framework of stress, make numerical computer solution for 2D thermal stress then stress analysis of the airplane. The second part focused on the most recent developments of FEM, and this method generates new techniques for solving these problems, such as the 1D, 2D, and 3D finite element models; the dynamic program method (DPM); the finite discrete element method (FDEM); and the finite element extended method (FEXM). The third part of this study presented the reservoir finite element simulation used for injection well testing inside unconsolidated oil sand reservoirs. Also improvement of the FE software program for the analyses, finite element extended approach to convert a 3D fault model were introduced. In addition, the study explored the development of a 3D and 4D model utilizing Visage for FEM analysis for geomechanics investigations, and the software eclipse for pressure drop prediction in carbonate reservoir weak formation and presented the Finite-Element Smoothed Particle Method (FESPM).

The use of miniaturised seismic sources for reduced environmental impact

Reducing the widths of seismic cutlines helps to minimise the environmental impact of acquiring seismic surveys. This can be accomplished by utilising miniaturised seismic sources, but not all small sources provide sufficient energy for imaging deeper oil sands reservoirs at the required resolution. In the winter of 2020, two independent 2D field trials were conducted to test the use of miniaturised seismic sources for imaging both shallow and deep oil sands reservoirs in Canada. This case study examines the results for frequency content and potential reduction in environmental impact as compared to conventional oil sands explosive sources. The resolution and signal-to-noise ratio of the seismic records from miniaturized seismic sources were matching and equivalent to the conventional seismic source.

A Deep Learning Method for Facies Recognition from Core Images and Its Application: A Case Study of Mackay River Oil Sands Reservoir

There is a large amount of drilling core data in the Mackay River oil sands block in Canada, and the accurate identification of facies from the cores is important and necessary for the understanding of the subsurface reservoir. The traditional recognition method of facies from cores is by human work and is very time consuming. Furthermore, the results are different according to different geologists because of the subjective judgment criterion. An efficient and objective method is important to solve the above problem. In this paper, the deep learning image-recognition algorithm is used to automatically and intelligently recognize the facies type from the core image. Through a series of high-reliability preprocessing operations, such as cropping, segmentation, rotation transformation, and noise removal of the original core image, that have been manually identified, the key feature information in the images is extracted based on the ResNet50 convolutional neural network. On the dataset of about 200 core images from 13 facies, an intelligent identification system of facies from core images is constructed, which realizes automatic facies identification from core images. Comparing this method with traditional convolutional neural networks and support vector machines (SVM), the results show that the recognition accuracy of this model is as high as 91.12%, which is higher than the other two models. It is also shown that for a relatively special dataset, such as core images, it is necessary to rely on their global features in order to classify them, and, with a large similarity between some of the categories, it is extremely difficult to classify them. The selection of a suitable neural network model can have a great impact on the accuracy of recognition results. Then, the recognized facies are input as hard data to construct the three-dimensional facies model, which reveals the complex heterogeneity and distribution of the subsurface reservoir for further exploration and development.

A review of the applications of magnetic susceptibility measurements for improved reservoir characterization

In the past, the application of magnetic susceptibility of diamagnetic and paramagnetic minerals to the study of rock magnetism was believed to be limited, due to both of their susceptibility signals being small compared to those of minerals in other magnetic. However, recent works have proved the usefulness of diamagnetic and paramagnetic susceptibility for reservoir studies. This paper summarizes results from previous studies showing the application of magnetic susceptibility measurements for characterizing different reservoir properties. Studies on the magnetic susceptibility of crude oils from different oil field regions around the world have shown good correlations of the susceptibility values with crude oil densities as well as other physical and chemical properties. In other studies, the measurements of magnetic susceptibility at the low and high fields have also been applied on rock core samples collected from different types of oil and gas reservoirs such as clastic shoreface, carbonate, shale and oil sand reservoirs. The magnetic susceptibility measurements for core samples without damaging the core by using the probe magnetic technique is probably used as a rapid, reasonable screening method for the initial estimation of core samples. The susceptibility of rock samples does not only show good correspondence with other reservoir characterizing methods, such as downhole gamma ray, spontaneous potential logs and core permeability, but it also shows some advantages over the traditional ones. The results suggested that the measurements of magnetic susceptibility could be used as an independent and improved method for distinguishing crude oil from different types of reservoirs, identifying main lithologies and predicting the permeable zone of a reservoir as well as estimating clay mineral contents.

Pore Pressure Estimation for Shaly Sand Formations Using Rock Physics Models For Compressional and Shear Velocities: A 1D Geomechanical Approach

Pore pressure estimation in sedimentary basins has been made exclusively through the compressional velocity data since the 1960s, using the normal compaction trend and lithostatic pressure profile derived from wireline logs. Considering that seismic velocity is highly dependent on petrophysical parameters such as porosity and clay volume, pore pressure estimation is commonly associated with a high degree of uncertainty due to simplistic assumptions that neglect those dependencies. To improve that, we propose two empirical velocity models based on compressional and shear rock physics relations for pore pressure prediction in shaly sand formations. These formulations extend Bowers and Doyen formulae, linking compressional and shear velocities with effective stress and petrophysical parameters. Finally, we used a non-linear multidimensional inversion approach to calibrate the proposed models and apply them in the context of a 1D geomechanics and pore pressure prediction study of an upper cretaceous overpressured shaly sand oil reservoir. The results show good agreement with pore pressure data and pressure predictions from the traditional Eaton method. The advantage of the proposed approach is its consistency throughout the entire well-log petrophysical interpretation workflow, especially concerning porosity, clay volume and saturation.

Numerical Investigation of a Novel Bottom-Up Assisted Pressure Drive Process in Oil Sands Reservoirs with Shale Barriers

Steam-assisted gravity drainage (SAGD) is widely applied to recover bitumen and heavy oil resources. Reservoir heterogeneity, especially the presence of shale barriers, continues to challenge the performance of SAGD. A novel enhanced oil recovery process, bottom-up assisted pressure drive, is proposed to improve the oil production in the reservoirs with shale barriers. In this work, numerical simulation is applied to investigate the feasibility of a bottom-up assisted pressure drive process. A reservoir model with typical oil sand reservoir properties is developed considering shale barriers. The performance of bottom-up assisted pressure drive and SAGD is compared under the same reservoir conditions, including steam chamber development, oil production rate, cumulative oil production, and the pressure difference between injector and production. The inherent mechanisms associated with the bottom-up assisted pressure drive are also well understood and confirmed. In the bottom-up assisted pressure drive, a flat steam chamber is developed from the bottom of the reservoir in the early stage of the process and grows upward with the injection of steam. The large volume of the steam chamber and the huge contact area between steam and bitumen contribute to a high oil production rate. The peak oil production rate in the bottom-up assisted pressure drive is approximately three times that in the SAGD process. The cumulative oil production in the bottom-up assisted pressure drive is 20% higher than that in the SAGD process. The effect of shale barriers on bottom-up assisted pressure drive is less, indicating one advantage of this novel process over SAGD in oil sands reservoirs with shale barriers. The pressure difference in the bottom-up assisted pressure drive is greater than that in the SAGD process. The pressure drive is another mechanism for improving oil production. The calculated net present value (NPV) in the bottom-up assisted pressure drive process is 27% higher than that in the SAGD process. This is mainly attributed to the high oil production rate in the early stage of the process and high cumulative oil production. The simulation study in this work provides technical support for the future field applications of this novel recovery process.

Reconstructing a Three-Dimensional Geological Model from Two-Dimensional Depositional Sections in a Tide-Dominated Estuarine Reservoir: A Case Study of Oil Sands Reservoir in Mackay River, Canada

A tide-dominated estuarine reservoir is an important oil reservoir. However, due to the force of bidirectional water flow, its internal structure is complex, and the heterogeneity is serious. Accurately establishing the tide-dominated estuarine reservoir model is a great challenge. This paper takes the Mackay River oil sands reservoir in Canada as the research object to establish the elaborate geological model of a tide-dominated estuarine reservoir. Through the meticulous depiction of core data, 14 kinds of lithofacies and nine kinds of architectural elements are identified, and the lithological and electrical response in sedimentary architectural elements is established. On this basis, the plane and vertical distribution of architectural elements, as well as the spatial superimposition patterns, are depicted and characterized through well seismic combination and plane and section interaction, and the representative plane and section architecture maps are obtained as 2D training images (TIs) for multi-point statistical modeling. The 2D TI is scanned by 2D data template to obtain the multi-point statistical probability of the 2D spatial architectural pattern. Then, the 2D multi-point probability is fused to generate three-dimensional (3D) multi-point statistical probability by the probabilistic fusion. Finally, Monte Carlo sampling is used to predict the spatial distribution of architectures, and an elaborate geological model of a tide-dominated estuarine reservoir is established. Compared with the traditional sequential indication modeling method, the point-to-point error of the model section based on the 2D section reconstruction method is only 25.92%, while the sequential indication modeling method is as high as 58.52%. Even far from the TI, the point-to-point error of the 2D section model is 33.13%. From the cross-validation, the average error of the 2D section is 11%, while the sequential indicator modeling error is 23.1%, which indicates that the accuracy of 2D reconstruction of the estuarine reservoir model is high, and this method is suitable for the establishment of the tide-dominated estuarine reservoir model.

3D experimental research of innovative VH-SAGD to enhance recovery of thin layer oil sand reservoirs

In thin layer oil sand reservoirs, the vertical and horizontal combined wells steam assisted gravity drainage (VH-SAGD) can avoid validly the problems of low steam efficiency and the high heat loss induced by the traditional SAGD technology. However, there are few laboratory studies about steam chamber development and production performance on the VH-SAGD. To fill this gap, a 3D large-scale physical model with temperature sensors was designed based on the similarity criterion, the experiment was carried out to simulate the production process of VH-SAGD. Then the development characteristic of steam chamber was captured by monitoring the temperature distribution changes. Finally, the production performance at each steam chamber development stage was analyzed. The experimental results showed the steam chamber development experienced the formation stage, the longitudinal development stage, the lateral expansion stage and the stabilization stage. The formation of triangular cold oil area indicated the steam chamber is mature, and the appearance of smooth steam front funnel indicated the steam chamber stopped developing. This research revealed the steam chamber development characteristics and the production performance of VH-SAGD, which can provide a reference value for optimizing injection and production parameters and predicting recovery factor for VH-SAGD in thin layer oil sand reservoirs.

Subsurface waste heat recovery from the abandoned steam assisted gravity drainage (SAGD) operations

A considerable fraction of the energy injected during the thermal recovery of oil remains in the subsurface and wasted in the surrounding geological formations after the profitable life of oil wells is over. This work studied the concept of thermal energy extraction from the abandoned SAGD operations in oil sands reservoirs for generating electric power. The cold water is injected as a working fluid to extract heat after the oil production is ceased, and the produced hot water is fed to a surface binary cycle to generate electric power. The results show that an oil sands reservoir after SAGD operations could be regarded as an artificial geothermal system suitable for thermal energy extraction. It is demonstrated that a total net electric energy output of 57 GWh could be achieved based on a single SAGD well pair during a ten-year heat-extraction time, indicating the huge heat extraction potential at full field scale. The results show that the thermal energy conversion efficiency to electricity for the abandoned SAGD wells can reach as high as 12%. The demonstrated subsurface waste heat recovery from the abandoned SAGD sites revealed that between 15 and 36% reduction in CO2 emission could be achieved.

Semisupervised fuzzy clustering for facies analysis using extended elastic impedance seismic attributes

A novel method in seismic facies analysis is proposed to resolve the discrepancy between well and seismic facies concepts. Extended elastic impedance (EEI) attributes are ideally suited for facies analysis because they are representative of different elastic parameters of rocks. A semisupervised method aims to accept or reject seismic clustering based on the well facies interpretation. First, specific EEI logs/attributes are calculated after a feasibility study and EEI analysis of the well data set are used for facies analysis. Using EEI logs as input attributes prevents data deficiency as a result of upscaling of well-log data to the seismic scale in the learning process. Then, the seismic EEI attributes are calculated from prestack seismic data and used for seismic facies analysis considering a fuzzy clustering algorithm with parameters estimated from the well facies analysis stage. The fuzzy clustering methods using membership degrees in their algorithms are valuable tools to reduce uncertainties. To evaluate the method’s performance, 3D seismic data of an oil sand reservoir were selected as a case study. The comparison with previous crossplot methods in facies modeling confirmed the advantages of the presented results in seismic facies analysis. The seismic facies sections are sufficiently interpretable according to the geologic setting and correlate more with the well facies codes.

Rich solvent - Steam assisted gravity drainage (RS-SAGD): An option for clean oil sands recovery processes

The impact of steam generation on Steam-Assisted Gravity Drainage (SAGD) process economics and environmental impacts have led to various modifications of SAGD including solvent co-injection with steam. One example is the Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD) process where 1–5 vol% solvent is injected with the steam into the reservoir. The solvent travels with the steam to the edge of depletion chamber dissolving into the oil thereby mobilizing the oil more than would have been achieved with heating alone. This means lower steam-to-oil ratio and thus, greater thermal efficiency, lower emissions intensity, and water consumption intensity. However, processes where the majority of the fluid injected is steam are still overly emissive and expensive to operate. There is a need to develop carbon-neutral bitumen production processes. Rich Solvent-SAGD (RS-SAGD) aims at injecting mostly solvent into the reservoir with small amounts of steam to achieve radically lower emissions and water consumption intensities than that of SAGD. Here, a RS-SAGD process is investigated where the solvent content is >60 vol% by using detailed thermal-solvent reservoir simulation in an Athabasca oil sands reservoir. The results reveal that RS-SAGD yields higher oil rate than that of SAGD and the process has significantly higher energy efficiency, up to 96% lower emissions and water consumption intensities than that of SAGD. Given the performance of RS-SAGD processes, oil sands operators should consider such processes for future operations.

Reservoir Architecture in Tide-Dominated Estuary: A Case Study of McMurray Formation Oil Sand Reservoir in the Athabasca Block, Canada

This paper presents a detailed description of the sedimentary characteristics and architecture model of the tidal-dominated estuary reservoir in the Lower Cretaceous McMurray formation. Based on a thorough study of the core data, 13 lithofacies were recognized. The lithofacies associations were divided into nine types of architecture elements, that is channel, salt marsh, fluvial point bar, tidal point bar, mud flat, mixed flat, sand flat, tidal bar and offshore. Through the combination of high resolution seismic data and well data, the architecture model was established. The boundary surfaces of each architecture elements are depicted and the logging characteristics is concluded. The cross-section is constructed to reveal the superimposition model of different architectural elements with the seismic profiles. The plane and vertical distribution of architectural elements are revealed and the sedimentary model is constructed. In the longitudinal section of estuary, the architecture elements is fluvial deposits (channel, fluvial point bar, and salt marsh), tidal flat (mud flat, mixed flat, and sand flat), tidal bar, tidal flat and offshore from land to sea. In the cross section, tidal bar, sand flat, mixed flat, mud flat, tidal point bar and salt marsh are distributed successively from the center to the sides. Tidal bars and sand flats are the best reservoirs in terms of physical properties. We focus on the analysis of their architecture and summarize their stacking patterns. We propose tidal bars as compounds are lateral accretion. Tidal bar has high-angle continued lateral accretion, with a dip angle of 6–12°. Sand flat also has lateral-migrated characteristics, but their dip angle is 2–6° which is smaller than tidal bars. As a result, the dimension and stack of a single tidal bar and sand flat are quantified. The tidal bar was lateral stacking or vertical stacking with lateral-migrated or forward-migrated sand flat and existed vertical and lateral erosion-filling phenomenon. Tidal bars have width of 100–550 m and length of 800–2,400 m, and sand flats are 300–2,500 m long. Tidal bars and sand flats made up the best reservoirs. The study provides some insights for future research of estuarine sedimentary patterns and reservoir architecture.