Open Access
Oil & Gas Science and Technology - Rev. IFP Energies nouvelles
Volume 73, 2018
Article Number 9
Number of page(s) 14
Published online 06 April 2018

© C. Wang et al., published by IFP Energies nouvelles, 2018

Licence Creative CommonsThis is an Open Access article distributed under the terms of the Creative Commons Attribution License (, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.


Steam-Assisted Gravity Drainage (SAGD) is considered a proven technology for heavy-oil/bitumen recovery over the past decades (Ipek et al., 2008). In SAGD, steam is injected near the bottom of the pay zone and rises as the steam chamber expands; the heated oil has lower viscosity and tends to drain along the chamber edge towards to the producer located about 5–10 m below the injector (Butler and Mcnab, 1981; Butler, 1985). Its performance, however, can be significantly affected by reservoir heterogeneities (Richardson et al., 1978; Webb et al., 2005). An effective design of the SAGD process requires a detailed understanding of the complex effects of reservoir heterogeneities introduced by shale barriers and varying water saturation (i.e., lean zones) (Pooladi-Darvish and Mattar, 2002; Baker et al., 2008; Xu et al., 2014a).

Richardson et al. (1978) developed a mathematical model to study the effects of shale barriers on SAGD performance. The impacts of shale barriers were realized by a reduction in vertical permeability. The model illustrated that both the size and spatial distribution of shale barriers could play an essential role on SAGD production. In the experiments by Joshi and Threlkeld (1985), a box-shaped sand pack was filled with 20–30 mesh (0.84–0.58 mm in diameter) Ottawa sand, where shale barriers were represented by a series of 6 mm thick plastic sheets. Although the final SAGD oil recovery was reduced after a certain time, the initial oil production rate, however, was higher because the injected steam was diverted by the shale barrier to reach regions located above the shale barrier. Yang and Butler (1992) constructed similar models with 2-mm and 3-mm glass beads, while a thin shale layer was represented by a 0.4 cm thick, reinforced, phenolic resin divider. It was concluded that short shale barriers did not affect the recovery performance significantly. These observations were corroborated by numerical simulation studies presented by Chen et al. (2008), in which stochastic realizations of the shale distribution were constructed to model varying proportion and continuity of shale barriers. The shale barrier was modeled as a facie with low vertical permeability. Their results showed that thin and laterally-extensive shale barriers posed adverse impacts on steam chamber development, while short shale had only minor effects.

Another origin of reservoir heterogeneity stems from spatially-varying water distribution. Lean zones with high water saturation could act as thief zones causing severe heat loss (Xu et al., 2014a). Highly-permeable lean zones could also promote lateral spreading of the steam chamber. Law et al. (2003) studied the impacts of confining/non-confining top water zone with numerical simulations. Inefficient oil production and steam-to-oil ratio were observed as steam chamber expanded into the top water zone. Masih et al. (2012) conducted a similar study to assess the influences on heat transfer and production due to bottom water coning. They concluded that bottom water coning would reduce the oil mobility near the producer, resulting in a lower oil rate and a higher steam-to-oil ratio. A sensitivity analysis was presented in Ricardo (2013), in which the thickness of top/bottom water zones and the pressure of an overlaying gas cap were varied. Results of these studies highlighted the adverse impacts on SAGD efficiency due to heat loss through these heterogeneous features. However, quantifying the impacts of randomly-distributed water saturation (as often inferred from well log measurements) is lacking. Xu et al. (2014b) presented a simulation study, where the facies model was constructed stochastically, but the water saturation was assumed to be constant within each facies.

The aforementioned studies have provided many useful insights regarding the modeling of shale barriers/lean zones and their impacts on short-/long-term recovery performance; however, a set of input parameters for correlating reservoir heterogeneity introduced by shale barriers and lean zones to SAGD production performance are rarely defined. Another important consideration is the ability to formulate such parameters from well log or other petrophysical data alone, as it would facilitate the construction of data-driven or statistical models for SAGD production analysis.

A dimensionless Shale Indicator (SI) was implemented by Amirian et al. (2015) to parameterize the location and size of the shale barrier that is in the closest proximity to the well pair. A recent modeling study by Wang and Leung (2015) included a systematic investigation of the heterogeneous distribution of shale barriers and lean zones (top/bottom water layers) in SAGD process. A few drawbacks of their study include: (1) constant porosity and permeability were assigned to each facies; (2) distribution of lean zones within the pay zone was ignored; (3) shales were modeled as deterministic, uniform rectangular barriers distributed in horizontal direction; and (4) the size of the Low-Quality Sand (LQS) is limited to be one-grid block surrounding the shale barrier. Nonetheless, their models have incorporated a LQS that exists as a transition zone between the clean sand and shale barriers, depicting a more realistic representation of the geology commonly observed in the McMurray Formation (Smith et al., 2009; Hubbard et al., 2011). A set of parameters were derived following a sensitivity analysis of the heterogeneous distribution. Artificial Neural Networks (ANN) were employed to correlate those parameters to a number of SAGD performance indicators. ANN has also been used to analyze heavy oil recovery in a number of previous works (Queipo et al., 2002; Ahmadloo et al., 2010; Karambeigi et al., 2011; Popa et al., 2011; Zerafat et al., 2011; Popa and Patel, 2012; Amirian et al., 2015; Ma et al., 2016). In particular, ANN was implemented in Ma et al. (2015) recently to construct a series of data-driven models from an actual SAGD field dataset.

A major drawback of these previous studies is that the proposed parameters capture only limited characteristics of the nearest heterogeneous features; information regarding the overall shale distribution is not represented. The primary objectives of this study are to (1) extend the reservoir heterogeneity description to include stochastically distributed shale barriers and lean zones; (2) formulate and correlate a set of attributes pertinent to characterizing realistic distribution of shale barriers/LQS and lean zones to production performance measures; and (3) demonstrate the potential of data-driven models for correlating production time-series with reservoir heterogeneities. First, a series of 2D SAGD models based on typical Athabasca oil reservoir properties are constructed. Nested sequential indicator simulation is applied to model the heterogeneous distribution (continuity, size, proportions, permeability, location, orientation and saturation) of shale barriers, LQS and clean sand distribution. Next, a set of attributes are identified to represent the characteristics of reservoir heterogeneities. Finally, ANN modeling is used to correlate the pertinent system attributes and production performance measures.

This paper is organized as follows: first, detailed description of methodology and simulation models is presented; next, a set of attributes are identified to describe the reservoir heterogeneities; finally, ANN is used to study the relationships between these inputs and SAGD performance.

1 Methodology

1.1 Reservoir Model Description

A commercial thermal compositional simulator (Computer Modeling Group, 2013) is used to construct a 2-D (X-Z) numerical model, as shown in Figure 1. Assuming symmetry around the well pair, only one half of the reservoir is modeled. Petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, for the base case have been taken from representatives values of several pads in the Christina Lake project. Data including well logs and production data are extracted from the public domain (Ma et al., 2015). The pay-zone thickness is 30 m. The model is 51 m and 30 m in the x- and z-direction, respectively, with Δx = Δz = 1 m. This corresponds to a well spacing of approximately 100 m. A well length of 900 m is oriented along the y-direction. The injector-producer pair, which is 5 m apart, is located at 9.5 m from the bottom of the pay zone. The locations of the well pair are also shown in Figure 1. The model set-up depicts a confined drainage pattern, similar to many previous works such as Chen et al. (2008). The viscosity of the in-situ oil is 6 00 000 cp at the initial temperature of 18 °C. Figure 2 shows the oil viscosity profile with temperature. For all simulations, 100% quality steam is injected at 1900 kPa continuously for a total simulation time (ts) of 20 years. A pre-heating period of 2 months is modeled.

thumbnail Figure 1

Configuration and set-up for one half of a symmetric 2-D (X-Z plane) SAGD simulation. Reservoir length (L = 51 m) and thickness (H = 30 m) are indicated.

thumbnail Figure 2

Oil viscosity profile as a function of temperature.

1.2 Facies and Rock Property Modeling

A number of conceptual models have been proposed to describe the middle unit of the McMurray Formation. One commonly-adopted model consists of two particular facies: Cross-Stratified Sandstone (CSS) and the Inclined Heterolithic Strata or IHS (Hassanpour et al., 2013). Porosity, permeability and oil saturation are high within the CSS, while characterization of IHS is more complex. It consists of many inclined sets of alternating sandstone and mudstone. These IHS sets can be described as either sandy or muddy, depending on the amount of mud content. The IHS deposits may contain centimeter-scale features that extend over kilometers. Object-based modeling techniques (Hassanpour et al., 2013) have been proposed in recent years to capture the complexities of these features. However, this type of modeling is quite complicated and time-consuming, and it often requires calibration with outcrops.

In this work, a simpler and more widely-used covariance-based technique is implemented to model the distribution of these heterogeneous features. Three different rock facies are modeled: clean sand, shale barrier and LQS. The LQS represents a transition zone between the clean sand and the shale barrier; it also depicts a mixture of muddy and sandy IHS at the larger scale. The LQS is also important for modeling water saturation variability among the reservoir; the presence of clay materials would result in an increase in capillarity and higher initial water saturation.

To model the facies distribution, nested sequential indicator simulation (Deutsch, 2002) is applied to stochastically model shale barriers, which are imbedded in a region of LQS, among a background of clean sand. Within each facies, porosity values are populated using sequential Gaussian simulation (Deutsch and Journel, 1998). LQS properties are modeled to depict a continuous gradation between shale barrier and clean sand. The histograms of porosity for the three individual facies are shown in Figure 3ac, while the semi-variogram (γ) for the facies modeling is presented in Figure 3d. Multiple realizations of facies and property distribution are modeled.

Same value of thermal conductivity is assigned for all three rock types, as suggested by Hampton et al. (2013), while different fluid thermal conductivities are assigned (Yang and Butler, 1992). These values and other reservoir properties are shown in Table 1. These parameters are comparable to those presented in the experimental studies of Yang and Butler (1992) and simulation studies of Chen et al. (2008). Chen et al. (2008) assumed that the presence of shale in sand reduces the vertical permeability dramatically but has no effect on the horizontal permeability. Following their suggestion, a constant horizontal permeability of 5 D is applied to all three facies in this study, and factors of 10−8–10−4 and 0.2–0.8 is applied to the kv/kh in shale barriers and clean sand, respectively, which are similar to the values provided in Chen et al. (2008) and Dang et al. (2010). The continuous variation in kv/kh within each facies is modeled by sequential Gaussian simulation. The variation in kv/kh ratio in the LQS is modeled as the arithmetic average between the clean sand and shale barrier.

thumbnail Figure 3

Modeling of facie and porosity distribution: (a-c) histograms of porosity distribution in clean sand, LQS and shale facies; (d) semi-variograms along the direction of maximum anisotropy for the facies modeling.


Reservoir and fluid properties.

1.3 Saturation Modeling

Archie model (1942) is used to model the varying saturation distribution within the reservoir as a function of local porosity and formation resistivity: (1) where a, m = cementation factor; n = saturation exponent; φ = porosity in fraction; Rt = true or formation resistivity, and Rw = water resistivity. McCoy and Grieves (1997) demonstrated that values a and m do not vary significantly for different facies; however, n is observed to be the highest for clean sand and the lowest for shale barrier. The values of Rw and Rt can be derived from the well log measurements. Values of these parameters, as summarized in Table 2, are assigned based on the representative trends for different rock groups presented in Palacky (1987). The formation resistivity is assumed to be constant within the facies. An example of facies, porosity and water-saturation distributions is shown in Figure 4. In these models, Sw in sand or LQS is typically ≤0.2 (ranging between 0.15 and 0.3), while Sw in shale is close to 1. These ranges are in agreement with log data from the field.


Parameters in archie equation.

thumbnail Figure 4

Facies, porosity and water-saturation distributions for a randomly selected realization.

1.4 Multiphase Flow Functions

Relative permeability relationships of oil-water and gas-liquid systems for all three facies are adopted from Wang and Leung (2015), in which it was concluded that capillary pressure could not be ignored, especially when shale barriers are extensively distributed and present in regions between the injection and production wells.

1.5 Performance Ranking

The following dimensionless indicator based on oil Recovery Factor (RF) and Cumulative Steam-to-Oil Ratio (CSOR) is implemented: (2)

where RF = COP/OOIP = Cumulative Oil Production/Original Oil In Place and CSOR = Cumulative Steam-to-Oil Ratio. Another measure based on the concept of Discounted Barrel (DB) of oil is also implemented (Wang and Leung, 2015). It takes into account the economic impact of steam consumption and variation in fluid properties. In the simplest term, it represents the net energy that can be obtained from the process.

Another important variable in describing the efficiency of steam injection is tiSOR, which is defined as the duration over which the monthly average Steam-to-Oil Ratio (iSOR) exceeds 5 (a commonly-accepted upper limit for typical SAGD wells). For a given value of COP, low values of tiSOR and CSOR would correspond to higher steam injection efficiency. A dimensionless form defined as tDiSOR= tiSOR/ts is considered as an output attribute in the ANN modeling. In this work, ts = 7304 days (20 years).

1.6 Neural Network Modeling

The ANN is an artificial intelligence technique useful for approximating the complex nonlinear relationship between a set of input and target variables. A schematic of various elements of an ANN consisting of only one hidden layer is illustrated in Figure 5. The network consists of an input layer, an output layer and a number of hidden layers. A series of neurons are assigned in the hidden layers. Weighted summation of the signals from the input layer is calculated according to Equation (3): (3)

where Yj is weighted sum of input signals at node j; w0 is threshold (bias); wij is the weight associated with the connection between node j and the input node i; xi is the signal of input node i; n is number of input nodes. An activation function is applied to the weighted sum according to Equation (4) to compute the output signal from node j, which is considered as the input signal to the next layer. (4)

Equations (3) and (4) are applied repeatedly until the final output layer is reached and value for the target variable is computed. Network parameters (i.e., weights and biases associated with each connection) are determined in a supervised learning procedure (Francis, 2001). For example, in a Back-Propagation Neural Network (BPNN), the error is back-propagated from the output layer to train the unknown network parameters in a gradient-descent minimization algorithm (Bishop, 1995), during which the mismatch between network predictions and known values of the target variables is minimized with a set of training data consisting of known input and output attributes. Due to the large disparity in scales of different data sources, normalization or standardization procedures are performed on all input and output attributes (Francis, 2001). The training dataset is also used to design the optimal network configuration. Readers may refer to various references for additional information about ANN (Zupan 1994; Shahab, 1995; Shahab, 2000, Al-Fattah and Startzman, 2001; Weiss et al., 2002). In addition, Principal Component Analysis (PCA) is performed to reduce the dimensionality of the original dataset (X) through a linear projection onto a lower-dimensional subspace. PCA is also useful for removing correlation among the inputs of the original dataset, while retaining much of its information. A mean-adjusted dataset (Z) is attained by subtracting the mean of each variable in X. Next, the covariance between two variables is calculated to eliminate bias due to large disparity in mean values. (5)where Xj and Xk represent two particular variables in X; M denotes the total number of samples in X. The calculation in Equation (5) is repeated for all pairs of variables to compute the covariance matrix, which is subjected to eigenvalue decomposition. Individual eigenvalue signifies the contribution of the variance from the corresponding eigenvector to the total variance of the original data. The eigenvectors with highest eigenvalues, or the Principal Components (PC), can be obtained by sorting the eigenvalues in decreasing order. Principal Scores (PS), which are regarded as new inputs attributes in subsequent ANN modeling, are computed using Equation (6). (6)

thumbnail Figure 5

An artificial neural network is an interconnected group of nodes. The circle represents an artificial neuron and the arrow represents a connection between two neurons.

1.7 Grid Sensitivity Analysis

In order to select a cell size that balances both accuracy (numerical dispersion) and computational efficiency, three different cell sizes (Δx × Δy) are tested: 1m × 1m (coarse), 0.5m × 0.5m (medium), 0.25m × 0.25m (fine), respectively. The average initial water saturation over the entire reservoir is 0.35, and the proportions of shale barriers, LQS and sand are 20%, 40% and 40% respectively. Only minor differences (less than 0.1%) in COP are observed among the three cases after 20 years of production. The run-time for the 0.25m × 0.25m model is 34 and 2154 times those of the 0.5m × 0.5m model and the 1m × 1m model, respectively on a 3.4 GHz, 16 GB of RAM, Intel® Core™ i7-2600 CPU. Therefore, a cell size of 1m × 1m is selected in this study.

2 Case Study

A suite of stochastic realizations of rock property distribution is constructed by varying facies proportions, vertical permeability, correlation range and orientation (i.e., continuity and direction of anisotropy) of shale barriers and LQS. Water saturation and lean zone distributions are modeled as described in the previous section. The reservoir is assumed to be composed of primarily clean sand, with the combined proportions of shale barriers and LQS to be less than 50%. In particular, LQS proportion is approximately 30–50%, while the shale barrier proportion is less than 10%, as LQS depicts a gradation of properties between shale barriers and clean sand.

In order to verify the negative impacts of lean zones, two particular scenarios are compared: (1) lean zones are distributed stochastically, and (2) mean saturation in the clean sand is assigned everywhere. It is clear that the steam chamber advances more quickly in the reservoir with stochastically distributed lean zones. Although a higher RF is observed, the corresponding CSOR is also increased; as a result, both R and DB decrease, while tiSOR increases. Lean zones may accelerate the expansion of steam chamber by providing alternative pathway for water drainage and serving as easy conduits for steam entry, as steam does not need to mobilize the bitumen in order to gain penetration into the reservoir. However, additional energy is consumed to vaporize the water in the lean zones. This observation illustrates the importance of capturing the effects of Sw variations in the analysis.

A number of parameters related to these heterogeneous features are introduced and explained in Figure 6. Here, the correlation lengths of the LQS and shale barriers along the maximum direction of anisotropy (LLQS and Lsh) are normalized against the total reservoir length in the x-direction (L): LDLQS = LLQS/L and LDsh = Lsh/L, respectively. Similarly, the correlation lengths along the minimum direction of anisotropy (HLQS and Hsh) are normalized against the total reservoir thickness (H): HDLQS = HLQS/H, and HDsh = Hsh/H. Since the physical thickness of a shale barrier is generally smaller than the resolution of the numerical model, Hsh is assumed to be the size of a single grid block of 1 m; as a result, HDsh is also a constant. Orientation of these heterogeneous features is represented by the azimuth angle or θ, which is measured anti-clockwise away from the x-direction. θLQS in the LQS is assumed to be the same as θsh in the shale. The rationale is that LQS serves to model the transitioning property between a shale barrier and the background clean sand; it essentially represents a shaly region near a shale barrier. It would be reasonable to assume that the geological processes contributing to the formation of both shale barriers and shaly regions to be similar; hence the orientation should be the same. A range of value between 0 and 300 has been used for θsh. Prior to ANN modeling, these azimuth angles are normalized to dimensionless forms as: θDLQS= θLQS/360° and θDsh = θsh/360°. These parameters have sufficiently captured the essential information extracted from the semi-variogram models. In addition, the dimensionless shale indicator SID = V/dminwH is considered, where dmin refers to the closest distance between a shale barrier and the producer, and w is the width of the reservoir. The product dminwH describes the volume of rock between the vertical plane at the heel of the well pair and the corresponding shale barrier; SID essentially represents the ratio of the shale-barrier volume to the rock volume that exists between the well-pair and the shale barrier. A thick shale barrier located close to the well pair can be reflected by a high SI value. Other parameters including average kv/kh and average water saturation in reservoir are computed. All these variables are considered as input attributes for the subsequent ANN modeling, and their ranges are summarized in Table 3.

A dataset consisting of a total of 249 cases with stochastically distributed facies, rock properties and lean zones is assembled for ANN modeling. The total dataset (m) is partitioned into two parts: (1) m1 samples are designated for training and validation of the BPNN model; an n-fold cross-validation is implemented to identify the optimal network architecture (Ma et al., 2015); and (2) the remaining (m2 = m−m1) samples are assigned for final testing in a prediction mode using the previously trained network parameters. In this study, the entire dataset is subdivided into 209 cases for training and validating, with the remaining 40 cases for testing.

ANN modeling is implemented in Matlab (R2009b) to correlate the non-linear relationships between the extracted input attributes and multiple SAGD performance indicators (R, DB and tDiSOR). A total of 10 dimensionless input attributes including LQS proportion, LDLQS and HDLQS, shale proportion, LDsh, θDsh, SID, kv/kh in clean sand and shale, and are adopted in this work.

thumbnail Figure 6

Schematic illustrating the definitions of various parameters employed in this study.


Range of dimensionless input attributes for ANN modeling.

3 Results and Discussion

Cross-plots between actual target values and the network predictions for the training datasets are shown in Figure 7. The predictive quality of the ANN models is quantified by the coefficient of determination (R2) and Mean Squared Error (MSE) between the target and predicted values. The corresponding results are compared in Tables 4 and 5. Overall, reasonable agreement is observed between target and predicted values. The results demonstrate that the parameterization scheme is useful for capturing reservoir heterogeneities pertinent to production performance, as evidenced by the high R2 and low MSE values corresponding to all three outputs for both training and testing datasets. The results for the testing dataset are also shown in Figure 7. It appears that model predictability for tDiSOR is not as good as for the other two output variables, as minor deviation between target and predicted values is observed. Considering that some of the input parameters are correlated (e.g., is related to facies proportions), it is postulated that removal of data redundancy may improve the model robustness and predictive capability. Therefore, PCA is performed next to remove correlation among the input parameters in the original dataset.

Figure 8 shows the variance contribution of each principal component in decreasing order. The variances of the first six components appear to dominate (accounting for >99.6% of the total variance), suggesting that the remaining four components can be neglected. Therefore, the modeling has been repeated after reducing the dimensionality of the original input space to 6. The application of PCA has reduced the number of input attributes to 6 principal scores. The results are summarized in Figure 9 and Tables 4 and 5. The ANN performance with only 6 PCA-transformed inputs is comparable to that obtained with all 10 original input variables. The results would suggest that there is some redundancy among the data; for instance, SID, and are dependent on the other input variables, as they are computed based on realizations generated from the other variables. This dependency can be removed via PCA, and reducing the dimension does not compromise the model predication. Another important remark is that with a relative small set of input variables (10 in this case), which have been selected with care to capture much information about the underlying heterogeneity and to minimize internal data redundancy, it is reasonable to expect that the removal of internal data redundancy would not lead to a significant improvement in model training and prediction; nevertheless, it is an important step in enhancing the robustness of data-driven models. Given the wide range of heterogeneity in the dataset, the results support the validity of the proposed set of parameters for correlating reservoir heterogeneity introduced by shale barriers and lean zones to SAGD production performance. It is highly possible that a group of reservoir models with similar characteristics would exhibit similar production behavior; future work should incorporate techniques such as cluster analysis to identify these internal data groupings.

Due to the randomness often associated with stochastically-distributed properties in heterogeneous reservoirs, parameterization of these properties for correlating against SAGD production performance is not well defined in the literature. In contrast to other recovery technologies, SAGD production is highly dependent on effective steam chamber growth, it is particularly important to capture heterogeneous features that have significant impact on steam chamber development.

It is proposed that the same parameterization strategy can be adopted when analyzing actual field data. However, in most practical scenarios, petrophysical logs are available only at vertical delineation wells (Ma et al., 2015), rendering conditioning data for heterogeneity modeling to be available at just a few sampled locations. To explore the potential implications of this limitation, the modeling workflow is repeated, where only information along the vertical direction of wellbore is extracted to calculate the input attributes. This procedure aims to replicate a practical field dataset. Some modifications have to be made in the input attribute formulation. For example, parameters including θDsh, LDLQS and LDsh are omitted, as they are difficult to be inferred from well log data alone (additional geological studies and understanding of the depositional environment are needed to constrain these parameters). With a reduced input attribute space and less redundancy among data, no PCA is applied. Therefore, a total of 7 input variables and 3 outputs are employed. It is obvious that the extracted input variables would capture only a portion of the information related to the reservoir heterogeneity. The objectives of this analysis are to: (1) assess the performance of ANN models when only limited petrophysical information is available; and to (2) illustrate the potential implications of ignoring inter-well heterogeneities. To facilitate reliable comparison with the previous results, the same 249 data samples of the training and testing are used here, and the results are presented in Figure 10. Though more scattering can be observed in comparison to Figures 7 and 9, most data points follow the 45° line. As shown in Tables 4 and 5, although the prediction accuracy has dropped, comparing to the ANN models constructed in the previous section, a reasonably high coefficient of determination (approximately 0.8) can still be achieved. Simulation studies and field experience have confirmed that SAGD performance is more sensitive to the variability in lateral extent, rather than thickness, of the shale barriers, it is expected that not capturing the effects of θDsh, LDLQS and LDsh would, to a certain extent, compromise the model fidelity. The results show that the reduced set of input parameters is still highly correlated to SAGD performance, highlighting the robustness of the proposed parameterization scheme. If data, either dynamic (e.g., 4D seismic and temperature measurements) or static (regional geologic mapping) is available to estimate the lateral distribution of the shale barriers, it can be readily incorporated to constrain the 3 missing input variables.

thumbnail Figure 7

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions using all 10 original input attributes: training dataset (top) and testing dataset (bottom).


Coefficient of determination (R2) for ANN modeling.


Mean Squared Error (MSE) for ANN modeling.

thumbnail Figure 8

Principal component analysis of the original input dataset.

thumbnail Figure 9

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions using 6 principal scores as input attributes: training dataset (top) and testing dataset (bottom).

thumbnail Figure 10

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions for the case where inter-well heterogeneities are ignored by using all 7 original input attributes: training dataset (top) and testing dataset (bottom).


A set of 2D models capturing a range of heterogeneous features commonly encountered in SAGD reservoirs are constructed. The petrophysical properties are representative of a typical reservoir in the Athabasca oil sands. Continuity, size, proportions, permeability, location, orientation and saturation of shale barriers and a surrounding region of degraded rock properties referred (LQS) are modeled stochastically. Capillarity and relative permeability effects, which have been ignored in many previous simulation studies, are incorporated in the shales to model bypassed oil trapping. Despite these aspects of heterogeneities have been studied to various extents in the past, the models used in this paper have integrated all these effects into a single comprehensive dataset.

The main objective of this study is to identify a set of parameters for correlating the effects of heterogeneities in lean zones and shales to SAGD performance. Ten dimensionless input attributes including LQS proportion, LDLQS and HDLQS, shale proportion, LDsh, θDsh, SID, kv/kh in clean sand and shale, and are formulated to capture the heterogeneities due to proportions, location, orientation, continuity and saturation of different facies. Three production performance indicators (R, DB and tDiSOR) that take into account both recovery factor (RF) and cumulative steam injection efficiency (CSOR) are employed to facilitate the comparison of production performance. An artificial neural network involving the ten input attributes and three production performance indicators is constructed. It is observed that removal of internal data redundancy (or correlation among input parameters) with techniques such as PCA is helpful for improving model robustness and accuracy.

Modeling of heterogeneous reservoirs is often facilitated by random variables and multiple realizations; however, parameterization of stochastically distributed properties for the purpose of production correlation is not well understood, particularly in SAGD reservoirs. Therefore, an important contribution of this work is that it explores and proposes a set of dimensionless variables that are demonstrated to correlate reasonably well with a number of production performance indicators.

A particular case study is presented to assess the utility of these parameters and the predictability of the ensuing ANN models, when only limited information is available along the vertical direction above a given well pair. The results, though not as good as those where inter-well heterogeneities are accounted for, demonstrate promising potential in the application with practical field dataset typically consisting of only petrophysical logs. This work also highlights the feasibility and utility of data-driven models in correlating SAGD performance. Future work should model the effects of gas cap. It should also incorporate time series data such as the oil rate and instantaneous SOR as the ranking criteria.



aw: constant, dimensionless

ao: constant, dimensionless

co: constant, dimensionless

cw: constant, dimensionless

Cw: specific heat for water, J/kg/°C

d: distance between shale barrier and producer, m

f(Y): activation function

H: reservoir thickness, m

Hsh: thickness of shale barrier, m

HLQS: thickness of LQS, m

HDsh: dimensionless thickness of shale barrier

HDLQS: dimensionless thickness of LQS

kv/kh: vertical-to-horizontal permeability ratio, mD/mD

L: reservoir length, m

Lsh: length of shale barrier, m

LLQS: length of LQS, m

LDsh: dimensionless length of shale barrier

LDLQS: dimensionless length of LQS

m: cementation factor, number of samples in a dataset

m1: number of samples for training and validation

m2: number of samples for testing

mw: water mass in kg per m3

M: number of samples in X

n: number of input nodes or saturation exponent in equation (1)

Qo: energy of produced oil per cubic meter, J/m3

Qw: energy required to generate one cubic meter of steam, J/m3

R: ranking indicator

R2: coefficient of determination

Rt: true or formation resistivity, Ω·m

Rw: water resistivity, Ω·m

Sw: water saturation, m3/m3

: average water saturation in reservoir, m3/m3

tiSOR: duration over which the monthly average steam-to-oil ratio exceeds a threshold, day

tDiSOR: dimensionless form of tiSOR

ts: simulation time, year

Ts: surface temperature, °C

V: volume of shale barrier, m3

Vw: vaporization heat for water, kJ/kg

w: width of reservoir, m

w0: bias

wij: weight associated with the connection between nodes i and j

xi: signal from input node i

Yj: weighted sum of input signals

ρo: oil density, kg/m3

γ: semi-variogram

ϕ: porosity in fraction

θ: orientation,°

θsh: orientation of shale barrier, °

θLQS: orientation of LQS, °

θDsh: dimensionless orientation of shale barrier

θDLQS: dimensionless orientation ofLQS


ANN: Artificial Neural Network

BPNN: Back-Propagation Neural Network

COP: Cumulative Oil Production

CSS: Cross-Stratified Sandstone

CSOR: Cumulative Steam-to-Oil Ratio

DB: Discounted Barrel

IHS: Inclined Heterolithic Strata

iSOR: monthly average Steam-to-Oil Ratio

LQS: Low Quality Sand

MSE: Mean Squared Error

OOIP: Original Oil In Place

PC: Principal Component

PCA: Principal Component Analysis

PS: Principal Score

RF: Recovery Factor

SAGD: Steam-Assisted Gravity Drainage

SID: Dimensionless Shale Indicator

SOR: Steam-to-Oil Ratio

X: original data vector

Z: mean-adjusted data vector


This research was supported by Nexen Energy ULC under the Collaborative Research and Development Grant program administered by Natural Sciences and Engineering Research Council of Canada (NSERC). The authors would also like to thank the University of Alberta for granting access to the Numerical and Statistical Server. Academic licenses for STARS are provided by the Computer Modelling Group (CMG) Ltd.


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All Tables


Reservoir and fluid properties.


Parameters in archie equation.


Range of dimensionless input attributes for ANN modeling.


Coefficient of determination (R2) for ANN modeling.


Mean Squared Error (MSE) for ANN modeling.

All Figures

thumbnail Figure 1

Configuration and set-up for one half of a symmetric 2-D (X-Z plane) SAGD simulation. Reservoir length (L = 51 m) and thickness (H = 30 m) are indicated.

In the text
thumbnail Figure 2

Oil viscosity profile as a function of temperature.

In the text
thumbnail Figure 3

Modeling of facie and porosity distribution: (a-c) histograms of porosity distribution in clean sand, LQS and shale facies; (d) semi-variograms along the direction of maximum anisotropy for the facies modeling.

In the text
thumbnail Figure 4

Facies, porosity and water-saturation distributions for a randomly selected realization.

In the text
thumbnail Figure 5

An artificial neural network is an interconnected group of nodes. The circle represents an artificial neuron and the arrow represents a connection between two neurons.

In the text
thumbnail Figure 6

Schematic illustrating the definitions of various parameters employed in this study.

In the text
thumbnail Figure 7

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions using all 10 original input attributes: training dataset (top) and testing dataset (bottom).

In the text
thumbnail Figure 8

Principal component analysis of the original input dataset.

In the text
thumbnail Figure 9

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions using 6 principal scores as input attributes: training dataset (top) and testing dataset (bottom).

In the text
thumbnail Figure 10

Cross plot of actual flow simulation target values of R (in black frame), DB (in green frame) and tDiSOR (in red frame) against network predictions for the case where inter-well heterogeneities are ignored by using all 7 original input attributes: training dataset (top) and testing dataset (bottom).

In the text

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