Steam-assisted Gravity Drainage Performance Research Articles

Data-driven analysis of using flow control devices and extended reach wells on SAGD well performance

The industry's current trend to reduce Capital Expenditures (CapEx) and to minimize the environmental impacts has led to drilling long lateral wells and developing key innovative tools like Flow Control Devices (FCDs). This study analyzed the relative performance of various FCD deployments using data from major Steam-Assisted Gravity Drainage (SAGD) projects in Western Canada, spanning from 1997 to mid-2022. The goal is to investigate the impact of FCD deployment and increasing the lateral length on SAGD well performance in terms of boosting oil produciton and lowering cumulative Steam Oil Ratio (cSOR).This paper utilizes a normalization technique to evaluate the production history of wells, considering geological and operational parameters. Following our confidential conversations with experts in the industry, wells exceeding 850 m in lateral lengths are labeled as “long”, while those below 850 m are labeled as “short”. Eventually, normalized oil production and cSOR for all wells are analyzed. A comparison is made between short and long wells that are completed or retrofitted with FCDs, giving an insight into the role of completion design on the relative performance of SAGD wells.Reservoir thickness and reservoir quality are assessed for each well using contour maps and Gamma Ray (GR) log images. These images are digitized using image processing codes developed in our study. On average, across all projects, wells equipped with FCDs produced up to 52% more normalized oil than those without FCDs, and cSOR decreased to 18%. Long wells, on average, had lateral lengths 38% greater than short wells and produced 18% more normalized oil than all short wells. When comparing long wells with and without FCDs, the normalized oil production is improved by up to 36%, and cSOR is lowered by up to 17%. Furthermore, comparing long wells with FCDs to short wells without FCDs reveals that the normalized oil production is improved by up to 96%, and cSOR is lowered by up to 26%. The results highlight the synergistic benefits of combining longer wells with FCDs to improve normalized oil production and cSOR. The historical production analysis show that installing FCDs is the key enabler and an innovative strategy to increase productivity, reduce cSOR, and make longer wells more productive.The findings indicate that FCDs might increase oil production and decrease cSOR for SAGD well-pad developments, allowing operators to reduce Greenhouse Gas (GHG) emissions intensity. The findings may be used to examine paradigm shifts in the development of heavy oil deposits as technology advances while keeping the project economics into account.

Feature engineering process on well log data for machine learning-based SAGD performance prediction

The conventional numerical simulation requires a reliable three-dimensional reservoir model to evaluate the steam-assisted gravity drainage (SAGD) performance, but it may be time-consuming and need a significant amount of static data. This study aims to develop a machine learning (ML) model that predicts the SAGD performance based on well log data from a near single well. Although the ML model is useful in capturing underlying non-linear relationships between input features and target features, it requires a large number of training data. However, the number of data is usually small in commercial fields, limiting the availability of all log responses as input features to consider reservoir heterogeneity. In case of using small dataset, the overfitting can occur with an excessive number of model parameters. Therefore, this study introduces a feature engineering process to extract and select key features from well log data to alleviate the overfitting problem.In this study, the feature engineering process was optimized by sensitivity analysis on feature extraction and feature selection methods. For data preparation, the 63 SAGD well pairs and their matched logged wells were screened from the six commercial oil sand fields in Alberta, Canada. The SAGD process mechanism and petrophysics were considered to build data screening criteria. Each depth of the log data was categorized into pay-zone or shale barrier. For feature extraction, sampling intervals were placed on log data. This calculates the net pay thickness, averaged gamma ray, deep resistivity, and neutron porosity logs in the pay-zone. In addition, the elevation of two shale barriers and the distance between the SAGD well and logged well are extracted. Sensitivity analysis of the sampling interval length was conducted to determine the optimal conditions considering heterogeneity and feature reduction. For the feature selection, various combinations of the extracted features were used to examine their inherent meaning for predicting the SAGD performance. The multi-layer perceptron model was trained based on various selected features to predict the SAGD performance indicators of a seven-year operation. The optimal sampling interval length was determined as 10m and the combination of gamma ray, deep resistivity, shale barrier elevation, and the distance information was selected as key input features. The model showed reasonable prediction results for SAGD productivity and economic indicator with R2 of 0.67 and 0.72, respectively.

Integration of machine learning and data analysis for the SAGD production performance with infill wells

AbstractThere have been numerous studies on predicting the production performance of the steam assisted gravity drainage (SAGD) process by data‐driven models with different machine learning algorithms since their introduction into industry. Similar efforts on SAGD infill wells, nevertheless, remain rare for this advanced alteration in improving the classical SAGD performance. On the other hand, predictive tools to optimize an infill well start time is useful in maximizing bitumen production and minimizing its costs. In this paper, a series of SAGD infill well models are constructed with selected ranges of operational conditions. Three SAGD infill well production performance indicators, namely, an increased ratio (), a total steam–oil ratio (SORtotal), and a stolen ratio () for each SAGD infill well, are calculated based on simulated infill well cases and control models. Five different machine learning algorithms (an artificial neural network [ANN] algorithm, three gradient boosting decision tree [GBDT] algorithms, and a support vector machine [SVM] algorithm) are trained, tested, and evaluated for their effectiveness in predicting those three indicators as output parameters, given seven SAGD relevant parameters as input parameters. Comparisons of different data sets show that the ANN is the best in predicting all three performance indicators under different infill well start times among all the above machine learning algorithms, while the GBDT algorithms have a better ability to learn a variation trend in the SAGD infill well performance.

Parallel particle swarm optimization for optimal SAGD operating scenario and well placement in a high dimensional search space

Steam-assisted gravity drainage (SAGD) has been commercially tested successfully in many oilfields with different characteristics. The operational parameters and wells’ location substantially affect the performance of SAGD, and designing a scenario optimization to find the optimum values of these parameters would enhance the efficiency of the process. Although most previous studies worked on optimizing some of the mentioned parameters separately, barely any optimized them simultaneously using a full 3D model since optimizing such a high-dimensional problem is time-consuming. In this study, whole-time scenario optimization is designed to simultaneously optimize the operational (steam injection rate, temperature, and production bottom hole pressure of all intervals) and well placement parameters of an 8-year SAGD. Parallel particle swarm optimization (PSO) is developed to determine the desired number of simulations concurrently to reduce computational costs. Also, the SAGD time is divided into four time intervals, and the effect of uniform and non-uniform time intervals on the net present value (NPV) and oil production is investigated. The outcomes showed that conducting parallel PSO would reduce the optimization time by 79.8%. Also, by applying the non-uniform intervals, the highest NPV is achieved, and the SAGD time declines to 6 years.

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.

A New Analytical Model for Predicting Steam-Assisted Gravity-Drainage Performance in the Plateau and Decline Stages

Summary Analytical models have been widely used to study the steam-assisted gravity-drainage (SAGD) process. Existing analytical models for this process either underperform or are limited in their applicability. In this paper, a new analytical model is developed to address these shortcomings. The new model consists of three major components. First, an equation for predicting oil production rate during the plateau stage was developed. This equation allows for permeability anisotropy in the reservoir, which is neglected in the majority of existing analytical models. Second, a novel and concise equation for calculating oil production rate during the decline stage was derived. This equation for the first time provides a general relationship between oil production rate during the decline stage and the properties of the reservoir together with key operating conditions and simultaneously mitigates the shortcomings of the majority of existing models (e.g., inapplicable in the decline stage of the SAGD process). Third, new correlations representing heat loss from the steam chamber to the overburden and heat transfer to oil-undepleted zone ahead of the chamber interface were derived; new predictive equations for estimating steam/oil ratio (SOR) in the plateau and decline stages of SAGD were obtained. The new model has been validated against a 2D scaled laboratory experiment and a set of field data. The results of this validation show that the new model predicts the oil production rate and SOR over the lifetime of an SAGD operation (excluding the short steam rise period) reasonably well. Predictions from the new model were also compared with several existing analytical models: The new model provided a closer match to actual measurements than other models. This robust model is grounded in more physics and incorporates reservoir geology and well operating conditions. It enables better understanding of the SAGD process and significantly improves the prediction of SAGD performance. Hence, it can be used to design new SAGD projects, predict existing projects, and optimize existing projects.

Study of novel steam assisted gravity drainage multilateral wells with dynamic gridding

SAGD (steam assisted gravity drainage) performance and its stream chamber growth are primarily determined by the vertical permeability of a reservoir. To deal with inter-bedded shale (IBS)-isolated intervals in bitumen reservoirs and improve steam chamber conformance, novel multilateral (MLT) wells with laterals and/or vertical legs in their trajectories are drilled to penetrate IBS. PetroChina Canada LTD. (PCC) has implemented MLT wells as a technology trial to evaluate potential mitigation to the presence of IBS in its MacKay River SAGD Project. Taking into account both accuracy and efficiency, dynamic local grid refinement (DLGR) is incorporated into the description of the mass and heat transfer phenomena in the vicinities of MLT wells. Also, to represent MLT injection and production wells as open hole branches, their lateral properties are adjusted by considering pore-scale mechanisms of fluid flow and heat transfer. With all these novel features established, the impacts of MLT wells on steam chamber growth and oil recovery are evaluated. It is discovered that MLT wells are conducive to increasing both injectivity and productivity due to the improvement of contact and drainage areas. Besides, how MLT wells perform with various steam operation strategies, geological parameters, injection pressure and NCG (non-condensable gas) wind-down scenarios is assessed.

Improving recovery efficiency by CO2 injection at late stage of steam assisted gravity drainage

The high recovery performance of steam-assisted gravity drainage (SAGD) makes it a popular option for heavy oil resources. Currently, most of the heavy oil reservoirs developed by SAGD in China are in the late development phase, with high energy consumption due to reduced thermal efficiency. The use of SAGD wind-down processes involving CO2 in combination with steam for heavy oil recovery is considered as a viable alternative to limit energy consumption, and also reduce the amount of greenhouse gas emissions by leaving CO2 behind in the reservoir. Study reveals that the dissolution and demulsification of CO2 steam chamber temperature reaches 200 ◦C, the amount of solid phase deposition induced in crude oil can reduce the viscosity of emulsified heavy oil by more than 50%. When the by CO2 extraction is only 0.016 kg/m3 , the rock wettability changes from lipophilic to hydrophilic, and the higher the reservoir temperature, the stronger the hydrophilicity is, which reduces the adhesion power of the oil phase and facilitates the stripping of crude oil from the rock surface. Numerical simulation studies have been carried out utilizing STARS to obtain energy efficient utilization and improved steam chamber characteristics. Heat loss from SAGD baseline is 1.77 times that with CO2 injection process, but the recovery factor is only 2.48% higher. At the initial stage with CO2 injection, the steam chamber continues its lateral expanding, which increases the recovery factor at the initial stage of CO2 injection by about 6%. One year after CO2 injection, gas channeling results in lower recovery than traditional SAGD process, and 38.4% of the injected CO2 is stored in the reservoir from this study. Cited as: Gong, H., Yu, C., Jiang, Q., Su, N., Zhao, X., Fan, Z. Improving recovery efficiency by CO2 injection at late stage of steam assisted gravity drainage. Advances in Geo-Energy Research, 2022, 6(4): 276-285. https://doi.org/10.46690/ager.2022.04.02

Experimental study on the effect of different distributed interlayer on SAGD performance

The Steam-Assisted Gravity Drainage (SAGD) technology is acknowledged in the development of heavy oils worldwide because of its high efficiency. This study is based on the Long Lake reservoir with large-scale interlayers in geovlogy. Firstly, a 3D experiment was built to evaluate the existence of different distributed interlayers on the performance of SAGD technology in consideration of its geology conditions. Our experiment investigated the effect of the equivalent area of interlayers on the behaviour of the steam chamber. The experiments were grouped into three scenarios, i.e., a) no interlayer, b) quarter-length-covered interlayer, and c) half-length-covered interlayer. The experiment observations demonstrate that the steam chamber expanding would be obstructed by the designed interlayers and then go around both sides of the interlayer to reach the top of the reservoir. The steam chamber would extend out along the top surface of the reservoir and go down until the end of production. It means that the existence of a different distributed interlayer can prolong the steady-production period and reduce the production of this period. Referring to scenario a, the EUR in scenarios b&c is decreased by 4.7% and 7.3%, respectively. Moreover, the longer distributed interlayer obstacle the propagation of the steam chamber significantly. The steady-production period in scenario c should be more extended than scenario b. Also, scenario c exhibited lower production and ultimate recovery. This study is helpful for the understanding of the effect of SAGD development on the different distributed interlayers and guiding the placing of wells on site.

Influence of top water on SAGD steam chamber growth in heavy oil reservoirs: An experimental study

Steam-assisted gravity drainage (SAGD) is one efficient and mature technology for recovering heavy oil and bitumen resources. The key underlying mechanism is the growth of the steam chamber after injecting steam. However, due to the complex geological environment, the thief zones exist and have a prejudicial effect on the development of the steam chamber, thus impacting the ultimate heavy-oil recovery. In this work, our objective is to investigate the effect of a top-water thief zone (i.e., water zone overlies the oil sand) on SAGD performance and further to understand the crucial mechanisms that control the heat loss during steam injection. A large-scale three-dimensional experimental apparatus is used to carry out the SAGD process with a top aquifer. Based on the similarity criterion, the field-scale model is transformed into a laboratory elemental model. To evaluate the SAGD performance quantitatively, the dynamic growth of the steam chamber is measured using the thermal detectors and the production data is recorded. The results show that the steam chamber exhibits three distinguished stages, that is, upward spread, lateral extension, and downward development in the presence of top-water zone. The bottom-water zone has less impact on the steam-chamber growth. The existence of a confined top-water zone, however, significantly affects SAGD performance, especially the lateral expansion of the steam chamber. The lateral propagation of the steam front is hindered by the top thief zone due to the heat exchange with the top water. Once the steam chamber reaches the boundary, the accumulation of energy in the water thief zone, in turn, can reduce the remaining oil saturation along the topwater–oil interface. This study provides us some key insights into the development of heavy oil resources with top thief zones when implementing SAGD technology.

Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty

Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV. • Sensitivity analysis under geological uncertainty of SAGD operational parameters. • Impact of small-scale variability of petrophysical properties in SAGD performance. • Deeper understanding of relevant injection parameters that influence the NPV and CSOR. • Comparison between deterministic statistical analysis and stochastic optimization.

A semi-analytical model based on unsteady conductive heat transfer in steam-assisted gravity drainage (SAGD)

Steam-assisted gravity drainage (SAGD) is one of the most successful in-situ recovery methods for bitumen reservoirs. Seeking the function of oil production with parameters of steam injection is significant for rapid performance evaluation of the SAGD process in fields. In this study, a new semi-analytical model based on unsteady conductive heat transfer is developed to estimate SAGD performance and describe the evolution of the steam chamber synchronously. These are implemented by interface velocity of steam chamber, as the function of the parameters of steam with the exponent-shape assumption and energy balance to link the oil output and chamber growth. It is worth mentioning that the equation of oil production is obtained based on the assumption of unsteady temperature distribution along with the interface, which is close to the real condition of the reservoir in fields. Then, the model is validated by using the Phase B, UTF project of the Athabasca reservoir. Finally, the impacts of steam injection parameters on SAGD oil production are discussed in this paper. Initial higher rate of heat injection to reach the production peak quickly and the subsequent lower rate for maintaining peak should be adopted to achieve the efficient target of oil production.

Breccia interlayer effects on steam-assisted gravity drainage performance: experimental and numerical study

Currently, the reservoir heterogeneity is a serious challenge for developing oil sands with SAGD method. Nexen’s Long Lake SAGD project reported that breccia interlayer was widely distributed in lower and middle part of reservoir, impeding the steam chamber expansion and heated oil drainage. In this paper, two physical experiments were conducted to study the impact of breccia interlayer on development of steam chamber and production performance. Then, a laboratory scale numerical simulation model was established and a history match was conducted based on the 3D experimental results. Finally, the sensitivity analysis of thickness and permeability of breccia layer was performed. The influence mechanism of breccia layer on SAGD performance was analyzed by comparing the temperature profile of steam chamber and production dynamics. The experimental results indicate that the existence of breccia interlayer causes a thinner steam chamber profile and longer time to reach the peak oil rate. And, the ultimate oil recovery reduced 15.8% due to much oil stuck in breccia interlayer areas. The numerical simulation results show that a lower permeability in breccia layer area has a serious adverse impact on oil recovery if the thickness of breccia layer is larger, whereas the effect of permeability on SAGD performance is limited when the breccia layer is thinner. Besides, a thicker breccia layer can increase the time required to reach the peak oil rate, but has a little impact on the ultimate oil recovery.

The Adverse Impact of Muddy Laminae on Conventional SAGD Performance and Improvement Strategy with the Multilateral Well Pattern

With further progress of Steam-Assisted Gravity Drainage (SAGD) technology, a growing number of oil sands or heavy oil reservoirs were put into production in an efficient way. However, owing to the existence of muddy laminae within reservoirs, there are challenges associated with the expansion of the steam chamber and oil drainage during the SAGD process. The purpose of this study is to evaluate the adverse impact of muddy laminae on conventional SAGD performance and introduce an improvement strategy with multilateral well patterns to reduce the adverse impact and improve the performance. In the research reported here, the reservoir numerical simulation approach is applied to conduct the research. The analysis conducted on a prototypical reservoir reveals that the steam chamber may expand slowly in some sections due to the poor capacity of heat and mass transfer, and the expansion of the steam chamber is relatively uneven along the wellbore, when the muddy laminae are existing in the formation. The influence level of the muddy laminae on conventional SAGD performance under different distribution modes is different, but the adverse effect is mainly reflected in the delay of peak oil production, the decrease in peak oil production, the decrease in steam chamber volume, and the increase in the cumulative steam oil ratio (mainly in early and middle stages of the SAGD process). On the basis of aforementioned researches, the improvement strategy with two different multilateral well patterns, planar multilateral well and upward multilateral well, is introduced to improve the SAGD performance. The results indicate that the combination of a planar multilateral injector and planar multilateral producer has the best performance. By adopting such kind of combination, the recovery factor can be increased from 31.36% to 47.08%, and the cumulative steam oil ratio can be decreased from 5.29 m3/m3 to 4.64 m3/m3 under the combined distribution mode of muddy laminae. It can be known that the branches of the planar multilateral well are very helpful for the expansion of the steam chamber and oil drainage, once the heat connection between branches of the injector and producer is well established. Overall results show that the multilateral well pattern is promising for SAGD applications at oil sands or heavy oil reservoirs which are rich in muddy laminae.

Experimental Comparative Investigation of Hot Solvent/Steam-Assisted Gravity Drainage in Oil Sand Reservoirs.

Hot solvent-assisted gravity drainage (HS-AGD) is an effective way to exploit oil sands and heavy oil both economically and environmentally. The visualized microscopic seepage experiments and two-dimensional (2-D) macroscopic simulation experiments of HS-AGD are carried out, and the results are compared with that of steam-assisted gravity drainage (SAGD) in detail for the first time in order to compare their development effects of the oil sand reservoir. MacKay River oil sand bitumen is taken as an oil sample in the experiments, with n-hexane as the solvent. Micro seepage characteristics of the hot solvent and steam and the remaining oil distribution of the solvent and steam drive are investigated through microseepage experiments. The expanding process of the solvent/steam chamber and production performance of HS-SAGD and SAGD are investigated through macrosimulation experiments. The study found that the sweep efficiency of hot solvent is higher than that of steam at the same temperature due to the small interfacial tension between the condensed solvent and heated bitumen. Due to the severe gravity segregation, the steam accumulated at the top of the model during the 2-D physical simulation experiment, which results in the huge heat loss at the top of the model. The temperature of the steam chamber is significantly lower than that of the solvent chamber. The oil recovery of 200 °C hot solvent vapor is twice as much as that of 300 °C steam owing to the different drainage mechanisms of the HS-AGD and SAGD. In SAGD, only heat transfer reduces the viscosity of oil sand bitumen. The components of oil produced in SAGD have little difference compared with that of the original bitumen. In HS-AGD, both mass transfer and the sensible heat transfer reduce the viscosity of oil sand bitumen. The in situ asphaltene precipitation induced by heated-solvent extraction also upgrades the bitumen. The results of component analysis show that in HS-AGD, the content of heavy components in the oil sand bitumen is obviously reduced. This paper aims to reveal the oil drainage mechanism of HS-AGD and SAGD from the macroscopic and microscopic view and to provide theoretical guidance for the field application of this technology.

Experimental Study on Well Placement Optimization for Steam-Assisted Gravity Drainage to Enhance Recovery of Thin Layer Oil Sand Reservoirs

SAGD (steam-assisted gravity drainage) technique is one of the most efficient thermal recovery technologies for exploiting Mackay River thin layer oil sand reservoirs. However, when making use of the traditional SAGD technique (the production and injection well are located on the same axis with the horizontal well spacing of 0 m), the steam chamber development is usually insufficient because of the high longitudinal sweep rate of steam, which seriously influences the SAGD performance for developing thin layer oil sand reservoirs especially. It is extremely important to find an economical and practicable method to promote the steam chamber development in thin oil sand reservoirs in the process of SAGD production; optimizing well placement is a reliable method. In this paper, an improved well placement method is proposed to enhance production performance of traditional SAGD, which is changing the horizontal well spacing to place the production well below of the side of the injection well (two wells are not located on the same axis). Three groups of 2D visualization experiments with different horizontal distances between two wells (0 cm, 10 cm, and 20 cm) were carried out, respectively, to observe the development and change of the steam chamber development, and to explore the EOR mechanisms. On the 2D experiment basis, optimal horizontal distance was selected to perform 3D physical simulation experiment to study and verity the production mechanism systematically. The results of 2D visualization experiment showed that the final oil recoveries of experimental groups with 10 cm and 20 cm horizontal distances were 7.6% and 2.3% higher than those of traditional SGAD (horizontal distance was 0 cm), respectively. Combined with 3D experimental results, the change in the horizontal relative position of two wells makes the steam first spread laterally between injecting and producing wells; thus, the lateral development of the steam chamber was promoted, and changes of temperature field also display that the lateral sweep area of steam was increased obviously and the form of steam chamber is changed. Meanwhile, the generation of appropriate horizontal well spacing can combine the effect of steam displacement and gravity drainage better and improve the sweep efficiency of steam. Nevertheless, the overlarge horizontal well spacing will also hinder the steam chamber development because the strength of steam overlap is weakened. Furthermore, the findings of this study help for better understanding that changing the horizontal well spacing can promote the lateral development of steam chamber, which can be used to enhance the oil recovery of thin layer oil sand reservoirs especially.

Numerical Simulation of Gas Mobility Control by Chemical Additives Injection and Foam Generation during Steam Assisted Gravity Drainage (SAGD)

ABSTRACT Gas mobility control is highly required to obtain a sufficiently-expanded and uniformly-developed steam chamber, which is conducive to steam-assisted gravity drainage (SAGD) production. Adding chemical additives with in-situ generation of foam (CAFA-SAGD) is an approach to improve sweep efficiency, displace residual oil and reduce heat loss, enhancing SAGD performance in terms of both oil production and steam oil ratio (SOR). With the input of the obtained chemicals and foam parameters and the consideration of the principle mechanisms (steam foam mobility control and IFT reduction), it depicts the dynamic distribution of components and compares the performance of CAFA-SAGD and SAGD with numerical simulation. Foam generation and foam collapse are also incorporated. Simulation study demonstrates that steam mobility control is conducive to generate a larger oil displacement area in the lower part of the model. Also, residual oil is more depleted owing to higher injection pressure and interfacial tension reduction. The optimization from this study ensures that the oil recovery factor is improved by 5.34%.

Analysis of Athabasca Oil Sands Investigates SAGD Performance Variability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195348, “Steam-Assisted Gravity Drainage Performance Variability—Analysis of Actual Production Data for 28 Athabasca Oil Sands Well Pairs,” by Quang T. Doan, Vincano; S.M. Farouq Ali, SPE, University of Houston; and Thomas B. Tan, SPE, Petrostudies Consultants, prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. Steam-assisted gravity drainage (SAGD) performance in bitumen-recovery projects in Alberta is affected by geological deposits, reservoir quality, and operational experience. The authors reviewed and analyzed actual field production and injection data for 28 Athabasca oil-sands-deposit SAGD well pairs (WPs). Based on analysis of field-production data, a numerical model was built and calibrated against production data from two of the poorer-performing WPs among the 28 studied. Agreement between simulated and actual cumulative oil and steam/oil ratio (SOR) was within 10% after 6 years of operations on a first-iteration basis. Problem and Investigation Methodology A survey of the literature reveals that some aspects of the SAGD process, particularly with regard to the behavior of gas, still largely are not understood. While successful history-matching simulations of SAGD WPs exist for several different projects, these rely on dead-oil pressure/volume/temperature treatment and exclude any findings and discussion on gas production. Such history-matched models likely would need to be modified significantly to be useful for modeling the wind-down stage of SAGD operations. Recent numerical studies modeling the generation of aquathermolysis gases focused on the injection of noncondensable gas into a mature SAGD steam chamber. In preparation for a series of numerical studies on aspects of SAGD performance, a reservoir model simple enough to be relatively adaptable for different geological settings was built. Such a model had to be calibrated rigorously with actual production data to provide a high degree of confidence in its results and predictive capability in appropriate contexts. The investigation in the complete paper is aimed at addressing several fundamental aspects of SAGD operations, including the effects of reservoir heterogeneities and the behavior of gas. The first part of the complete paper is focused on reviewing and analyzing actual field production data spanning more than 1,700 days from 28 SAGD WPs from four different pads (A, B, C, and D) of the Jackfish 1 project; this synopsis will not include that extensive data. Jackfish 1 Project. Jackfish 1 consists of 42 WPs divided into six pads (including the 28 WPs in Pads A, B, C, and D analyzed for the authors’ study) and is part of the geological oil-sands trend of the Athabasca oil-sands deposit. Jackfish 1 has a nameplate capacity of 35,000 BOPD, with a designed SOR of 2.7. Consistently exceeding 90% of its nameplate capacity since first steam, it is commonly considered to be a successful SAGD project. The results of data analysis for the WPs studied indicated the following: Considerable variance exists in the recovery performance of SAGD WPs on the same pad. Considering the small drainage area of the 7-WP pad (800×800 m), such variances bear important implications for the planning and execution of SAGD projects (particularly greenfield development but also with regard to brownfield expansion). The authors stress that forecasting project productivity should not be based on a single-WP, deterministic simulation model without any consideration for distributions in reservoir geology and parameters affecting SAGD performance. This assessment is equally applicable in the estimation of reserves.

Analytical model of steam-assisted gravity drainage (SAGD) process in relation to constant injection rate

Steam-Assisted Gravity Drainage or SAGD is a widely tested method for producing bitumen from oil sands (tar sands). Several analytical treatments of the basic process have been reported. In a typical model, the focus is on bitumen drainage ahead of an advancing steam-oil interface with no recourse to the steam injection rate – which is worked out after the fact.In this study, a comprehensive analytical model of the SAGD process in relation to constant injection rate, for the first time, was developed encompassing steam chamber rise, sideways expansion, and the confinement phases to evaluate the SAGD performance. The model is called Comprehensive Constant Heat Injection (CCHI). The accumulated heat ahead of the front plays a crucial role in SAGD modeling in order to find the advancing front velocity. There is a reciprocal relation between the advancing front velocity and the amount of stored heat ahead of the front. Considering the equilibrium situation for thermal recovery methods with dominant gravity drainage driving force, the advancing front velocity is responsible for heat accumulation ahead of the front, and in turn, the heated oil drains down to the production well and advances the front. Therefore, the key point in the modeling is to determine the advancing front movement that satisfies heat and mass balances over the system under equilibrium. In the CCHI model, after the rising chamber reaches the reservoir top, steam is injected at a constant rate into the system which is the case in the most field applications, and it provides heat for the growing steam chamber size, increasing heat loss, and heat flow by conduction ahead of the front. Unlike previous works, the steam chamber growth is maximum at the beginning of the sideways expansion phase with growth and oil production rate decreasing with time. It is believed that the inclusion of increasing heat loss and interface extension with time, ignored in previous works, into energy and mass balances results in decreasing steam chamber velocity. In this model, it is the first time that the SAGD oil rate is directly related to the steam injection rate. Some interesting analysis of a SAGD process can be extracted from the model. Also, the approach provides a tool for quick field-scale optimization and performance predictions instead of using extremely time-consuming thermal numerical simulators.

Automated Approach Optimizes Flow-Control Device Placement in SAGD Completions

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 193364, “Optimization of Placement of Flow-Control Devices Under Geological Uncertainty in Steam-Assisted Gravity Drainage,” by Siavash Nejadi, Stephen M. Hubbard, Roman J. Shor, SPE, Ian D. Gates, SPE, and Jingyi Wang, SPE, University of Calgary, prepared for the 2018 SPE Thermal Well Integrity and Design Symposium, Banff, Alberta, Canada, 27–29 November. The paper has not been peer reviewed. Steam-chamber conformance in steam-assisted gravity drainage (SAGD) influences the efficiency and economic performance of bitumen recovery. Conventional SAGD well-completion designs provide limited control points in long horizontal well pairs, leading to development of nonideal steam chambers. The complete paper presents an automated approach to optimizing placement of flow-control devices (FCDs) in SAGD well-pair completions. The methodology uses a coupled wellbore/reservoir model to simulate both reservoir fluid-flow behavior and detailed wellbore hydraulics. The qualities of the well-completion-design parameters and their effect on production are assessed by calculating the net present value (NPV), which is considered the basis for•optimization. Introduction The Lower Cretaceous McMurray formation hosts the majority of bitumen in the Athabasca oils sands—the largest known resource of bitumen. The formation is composed of large-scale fluvial-estuarine point bars and other laterally accreting channel systems that are highly heterogeneous. The formation has been interpreted as having three stratigraphic subdivisions: a lower continental (fluvial), a middle fluvial-estuarine unit (point-bar dominated), and an upper marginal marine deposit. The repeated erosional cut and fill events within the McMurray have led to nested and multiple stacked structures. Similarly, laterally accreting channel systems, such as point-bar deposits consisting of inclined heterolithic strata of sandwiched sand-siltstone sequences and abandoned mud channels, lead to very complex sedimentary facies relationships in which rock types change both laterally and vertically over very short distances. SAGD completions offer the most promise of producing bitumen resources from Athabasca oil-sands deposits. The SAGD well configuration typically consists of two parallel horizontal wells within a short distance, one above the other. Steam is injected into the upper well and fluids are produced from the lower well. These design schemes provide limited control of steam injection and liquid production along horizontal sections and adversely affect steam-chamber conformance. Operational difficulties, drilling, well completion, and reservoir parameters moderate overall SAGD performance. More specifically, these factors include hydraulic gradients and pressure drop in the tubulars, injectivity and productivity variations along the wellbore from plugging and formation damage, heat exchange, energy loss to bottom water, nonparallel well-pair placement, well undulation, and—most importantly—reservoir heterogeneity and structure. The conventional SAGD well completion needs to be modified to deliver steam efficiently throughout the reservoir interval, improve liquid-production performance, and minimize steam breakthrough.