Gravity Drainage Process Research Articles

Water Separation Performance in Bitumen Recovery from Athabasca Oil Sands: Implementation of Separation Efficiency Index

The oil (diluted bitumen)–water separation efficiency at steam-assisted gravity drainage (SAGD) process conditions has been evaluated in a laboratory environment by using a custom-built batch gravity setup, using SAGD field fluids and commercial gas condensate as a diluent. The key parameters and conditions investigated are solvent amount, shear conditions, water-to-oil ratio, and the presence and wettability of fine solids. The results demonstrate the complexity of the oil–water separation process, affected by the dependence of the investigated parameters from one another. A new quantification approach is introduced to facilitate the oil–water separation efficiency evaluation, based on the proposed descriptor, referred to as a separation efficiency index (SEI). Defined as the average of the residual water-in-oil and oil-in-water indices, SEI ranges from 0 to 1, where 1 represents a “perfect” (complete) separation and 0 corresponds to a complete emulsification. The SEI allows one to describe the separation efficiency throughout the entire separation vessel volume, using discrete vertical water distribution profiles, and represents the separation efficiency with a single number, regardless of the experimental approach taken. The findings show that in the range of solvent concentrations of 30 vol % or lower, the mixing speed affects the separation performance and becomes predominant at the relatively low solvent concentrations of 10 and 20 vol %. The amount of solvent added becomes predominant in the oil–water separation process and overcomes all other effects in the highest solvent addition (40 and 50 vol %) range. The presence of water-wet solids improves the separation performance, while the presence of oil-wet solids impedes the oil–water separation. The results presented in this study, in particular the proposed SEI, are important for improving the oil–water separation efficiency and can be used to develop operational envelopes and new solvent injection strategies, in terms of location, amount, and stages, further improving the quality of the oil product obtained in SAGD.

On geothermal energy recovery from post-SAGD reservoirs

In the steam-assisted gravity drainage (SAGD) process, large amounts of steam are injected into the reservoir to mobilize bitumen for its production to surface. The amount of thermal energy injected into the reservoir creates a man-made geothermal system that could be used to yield heat after the SAGD operation is complete. In the research documented here, for the first time, the amount of energy stored in the reservoir is evaluated and potential processes for recovery of the thermal energy are explored. The results reveal that after 10 years of SAGD, about 35% of the total injected energy in the steam remains in the reservoir rock from which the bitumen was extracted. After a 1 year blowdown stage at the end of the SAGD operation, ∼32% of the total injected energy remains in the reservoir rock. Three cases are used to explore the potential for recovering the thermal energy in the reservoir rock. The results show that the best case is one where a new horizontal well is added at the top of the reservoir above the SAGD well pair. In this case, >100 °C water was recovered at high rate for over 1,400 days realizing about 34% recovery of the thermal energy contained in the reservoir rock after the SAGD blowdown stage. The results demonstrate that there is potential for recovering the thermal energy. This recovered energy offers means to make the SAGD process more thermally efficient over its entire energy production life.

Molecular Dynamics Investigation of Wettability Alteration of Quartz Surface under Thermal Recovery Processes.

One of the primary methods for bitumen and heavy oil recovery is a steam-assisted gravity drainage (SAGD) process. However, the mechanisms related to wettability alteration under the SAGD process still need to be fully understood. In this study, we used MD simulation to evaluate the wettability alteration under a steam injection process for bitumen and heavy oil recovery. Various oil droplets with different asphaltene contents were considered to determine the effect of an asphaltene content on the adsorption of the oil droplets onto quartz surfaces and wettability alteration. Based on the MD simulation outputs, the higher the asphaltene content, the higher the adsorption energy between the bitumen/heavy oil and quartz surfaces due to coulombic interactions. Additionally, the quartz surfaces became more oil-wet at temperatures well beyond the water boiling temperature; however, they were extremely water-wet at ambient conditions. The results of this work provide in-depth information regarding wettability alteration during in situ thermal processes for bitumen and heavy oil recovery. Furthermore, they provide helpful information for optimizing the in situ thermal processes for successful operations.

Modelling temperature dynamics of the SAGD process in an oil reservoir by the discovery of parametric partial differential equations

AbstractMany chemical and industrial processes are complex, and the dynamics of such processes cannot be explained using a partial differential equation (PDE) or a system of PDEs with constant coefficients. Parametric PDEs, that is, PDEs with their coefficients varying across time or space, are utilized for this purpose. The non‐availability of data at all spatial locations and partially available process knowledge add to the complexity of modelling such processes. This paper proposes a framework to discover parametric PDEs using data‐driven and hybrid modelling approaches with the temperature dynamics of steam‐assisted gravity drainage (SAGD) process in an oil reservoir as the system under study. We utilize an ensemble of 200 realizations of the temperature dynamics generated using the variogram for the PDE discovery. Permeability, which is one of the oil reservoir's petrophysical properties, is used to develop the hybrid models. We infer that utilizing partial process knowledge aids in improving the model's accuracy.

Pore‐network modelling of combined molecular diffusion and gravity drainage mechanisms in a porous matrix block: The competitive role of driving forces

AbstractA large part of the world's hydrocarbon resources are located in fractured reservoirs, and mass transfer phenomena play a crucial role in enhanced hydrocarbon recovery from these reservoirs. Pore‐network models have been widely used to study kinetic and pore‐scale micro‐mechanisms. Molecular diffusion involves mass transfer and liquid–vapour phase change and can be simulated by a modified invasion percolation model. Despite the existence of separate pore‐scale studies on molecular diffusion and gravity drainage, no articles have been published that evaluate the combined effect of both mechanisms. This study investigates the competitive roles of the two phenomena and the effective factors controlling each mechanism with the aid of pore‐network models. According to the results obtained, gravity drainage and molecular diffusion would have a synergic effect when they are simultaneously active. Although for a single‐component liquid system, there would be a capillary holdup residual saturation in the pure gravity drainage process (between 11% and 14% for the evaluated cases) and a slow and lengthy evaporation in pure molecular diffusion (between 47% and 57% longer for the cases under study), our investigation revealed that when the two mechanisms coexist, a faster process with no residual liquid is expected. Our findings clarify that when the system is strongly gravity dominated, the liquid body remains integrated, gas–liquid contact recedes in a piston‐like manner, and three‐stage liquid desaturation is observed. Furthermore, highly clustered liquid saturation is observed in strongly capillary‐dominated systems, and the liquid desaturation curve in a capillary‐dominated model has two distinguishable stages. The competitive contribution of gravity drainage and molecular diffusion as the main driving forces of liquid extraction from a single‐block model is quantified for the entire period of desaturation. Depending on the dominance of the production mechanisms, the process is either gravity‐assisted molecular diffusion or diffusion‐assisted gravity drainage.

The effect of CO2-philic thickeners on gravity drainage mechanism in gas invaded zone

The rate of mass transfer between the fractures and matrix in gas invaded zone can significantly influence on the oil recovery during the forcedgravitydrainageprocess.However, in this study, a new approach was suggested to improve the gravity drainage process in gas invaded zone. Poly(fluoroacrylate) (PFA), as a CO2-philic thickener, was injected into the gas invaded zone to illustrate the impact of interfacial mechanisms such as gas diffusion coefficient and interfacial tension (IFT) on oil recovery. Also, the cloud point pressures were measured to ensure that the PFA did not come out of the solution due to a phase change during IFT, gas diffusion coefficient, and gravity drainage experiments.Results showed that the CO2-PFA thickener (20000 ppm) could decrease the IFT from 56 to 24 dyne/cm compared to the pure CO2 scenario, improving the gravity drainage mechanism in the gas invaded zone. In addition, the CO2 diffusion coefficients were increased approximately more than two times during CO2-PFA injection in comparison with pure CO2 injection in both porous media and bulk oil phase scenarios at reservoir conditions. Also, an incremental oil recovery of 16 percent was achieved during PFA/CO2 compared to pure CO2 injection in the gas invaded zone. Therefore, gas gravity drainage is the most important mechanism once gas thickener or CO2 enters the fractures in the gas invaded zone.

Rapid evaluation and optimization of carbon dioxide‐enhanced oil recovery using reduced‐physics proxy models

AbstractThe carbon dioxide (CO2) injection in oil reservoirs is a promising enhanced oil recovery method to reduce carbon emissions into the atmosphere. The CO2 injection simulation and optimization require a large computation time, especially in real large‐scale oil reservoirs. This paper integrates experimental design and machine learning to construct a reduced‐physics surrogate model alternative to the complex reservoir simulator. This surrogate model was used to evaluate and optimize the CO2‐assisted gravity drainage (CO2‐GAGD) process, applied to a clastic reservoir in the Rumaila oil field. In the GAGD process optimization, five operational decision parameters controlling the production and injection activities were manipulated to attain optimal future oil production. Hundreds of simulation runs were created by Latin Hypercube Sampling to build a proxy‐based optimization. The optimal scenario increased the cumulative oil production by 416 MMSTB at the end of 10‐year prediction period. Finally, four machine learning (ML) algorithms were built as proxy surrogates alternative to the complex compositional reservoir simulations: Quadratic Equation (QM), FUzzy logic‐GEnetic algorithm (FUzzy‐GEnetic), Multivariate Additive Regression Splines (MARS), and Generalized Boosted Modeling (GBM). To show how robust using the ML approaches for the fast CO2‐GAGD process optimization, the random subsampling cross‐validation was adopted to conclude the optimum proxy metamodel that provides the lowest mismatch between the proxy‐ and simulator‐based cumulative oil production. The GBM algorithm achieved the highest adjusted‐R2 (0.9973) and lowest root mean square prediction error to produce the most accurate metamodel. The resulting accurate GBM proxy metamodel can be used for fast optimization of the CO2‐GAGD process. Specifically, GBM‐metamodel should lead to achieving higher optimal reservoir flow responses, especially with running a large number of simulation runs. Consequently, this proposed trained GBM‐ML proxy metamodel could be used for gas injection optimization and uncertainty assessment with far‐less computational effort than with the conventional approaches, which use a complex flow simulator.

To extract geothermal energy from low-permeability reservoirs: Development and simulation of cyclic water injection (CWI)- and water-assisted gravity drainage (WAGD)-based processes

Geothermal energy is a clean energy source to fulfill the increasing global energy demands. For the first time, several energy extraction strategies are proposed and compared through numerical simulations for effective energy recovery from low-permeability geothermal reservoirs. We simulate geothermal energy extraction using either Cyclic Water Injection (CWI) or Water-Assisted Gravity Drainage (WAGD) processes with or without hydraulic fracturing over a 10-year operation. We evaluate the positioning of injector and producer in WAGD process, well spacing, addition of one injector, and the time variation of injection/soaking periods in CWI process. The simulations indicate that the fractured reservoirs generate more energy than those without fracturing; CWI-based processes exhibit higher energy recovery efficiency than WAGD process in terms of Energy-Water-Ratio (EWR). EWR, as a newly proposed parameter in this study, is defined as the energy production specific to per unit volume of water injected, which is useful in evaluating the cost-effectiveness of a geothermal energy extraction process. The gravitational effect proves to be the dominant factor that determines energy generation compared to phase change in WAGD process. In addition, formation and impacts of steam chambers in CWI and WAGD-based processes are discussed. Furthermore, statistical analyses are performed to evaluate the effects of reservoir temperature, pressure, permeability, and their mutual interactions on cumulative energy production. Eventually, two correlation models for predicting cumulative energy production based on these formation properties are proposed. This study provides a new perspective on implementing different innovative exploration strategies and optimization processes for energy extraction from low-permeability geothermal reservoirs.

A new analytical model to predict heavy oil production rate in the SAGD process

AbstractAn analytical model for predicting the oil production rate in the steam‐assisted gravity drainage (SAGD) process is presented in this article. The suggested correlation is found based on Butler's original work. It considers the most effective parameters of the process that emphasize the influence of gravity drainage and that are grouped together in the form of the Rayleigh's number. The present model introduces three coefficients (i, j, and k) into the equation, which are determined by minimizing an objective function based on the difference between the six experimental SAGD datasets and the calculated results. The tool chosen for the minimization is the genetic algorithm (GA). After the initial evaluation, the same approach is used for other reservoir characteristics to ensure the robustness of the new equation. Having considered various simulation outcomes with an average error of 8.9% makes this model a credible one for predicting the SAGD production rates. The novelty of the new predictive model lies within its unique approach, making it quite fast and applicable to a wide range of reservoirs with low associated estimation inaccuracies.

Experiments on Water Gravity Drainage Driven by Steam Injection into Elliptical Steam Chambers

Based on a recently published theoretical model, in this work we experimentally studied the problem of gravity water drainage due to continuous steam injection into an elliptical porous chamber made of glass beads and embedded in a metallic, quasi-2D, massive cold slab. This configuration mimics the process of steam condensation for a given time period during the growth stage of the steam-assisted gravity drainage (SAGD) process, a method used in the recovery of heavy and extra-heavy oil from homogeneous reservoirs. Our experiments validate the prediction of the theoretical model regarding the existence of an optimal injected steam mass flow rate per unit length, ϕopt, to achieve the maximum recovery of a condensate (water). We found that the recovery factor is close to 85% when measured as the percentage of the mass of water recovered with respect to the injected mass. Our results can be extended to actual oil-saturated reservoirs because the model involves the formation of a film of condensates close to the chamber edge that allows for gravity drainage of a water/oil emulsion into the recovery well.

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.

Experimental evaluation of Carbon Dioxide-Assisted Gravity Drainage process (CO2-AGD) to improve oil recovery in reservoirs with strong water drive

The Gas-Assisted Gravity Drainage (GAGD) process has been developed to improve and enhance oil production in both secondary and tertiary recovery stages. In the GAGD process, oil is produced through horizontal wells above the oil-water contact. Therefore, high levels of water cresting are probably happening, especially in reservoirs with active water aquifers. However, all the previous GAGD feasibility experimental studies have never been addressing the existence of active water aquifers. Consequently, the current research was conducted to test the immiscible GAGD process feasibility to improve oil recovery and minimize water cut in brown reservoirs with strong water coning tendencies.A Hele-Shaw model consists of two parallel glass plates packed with silica sand to visually discern the process performance. Specifically, the CO2-AGD process feasibility versus the Free Fall Gravity Drainage (FFGD) mechanism was investigated on the physical model with large, moderate, and without bottom water drive. The experimental results indicated that the GAGD process performance is higher performance than the FFGD in all runs because of its fast high oil recovery, especially when implemented on the reservoir without a bottom water drive. The immiscible CO2-AGD process is not only important in terms of increasing oil recovery, but it also significantly delays the gas breakthrough. The strength of the aquifer inversely impacts the gas breakthrough time as increasing the aquifer strength results in fast oil production and early gas breakthrough. Additionally, the immiscible GAGD experiments illustrated that oil recoveries in the FFGD and GAGD processes improved to 35% and 47% of OOIP for the model without bottom water drive, respectively. However, the oil recovery increased in the same FFGD and GAGD processes to 61% and 63% of OOIP for the model with a large bottom water drive, respectively. Specifically, the ultimate oil recovery during the GAGD process with a large bottom water drive was higher than the FFGD run with only 2%; while there is increasing in ultimate oil recovery for the model without the bottom water drive of about 12%. Consequently, the GAGD process is more efficient to improve oil recovery in reservoirs with limited or without bottom water drive.

Numerical Modeling of the Steam Chamber Ramp-Up Phase in Steam-Assisted Gravity Drainage

Due to the critical nature of the ramp-up phase of an efficient steam-assisted gravity drainage (SAGD) process, it is important to understand the physics of the steam chamber ramp-up phase in order to improve SAGD production performance. In conventional numerical simulation models, the dynamics of the steam chamber ramp-up phase are not fully resolved because of unclear steam–oil–water interactions during the vertical growth of the steam chamber and how its state changes as the reservoir parameters vary. This work provides an efficient approach for the numerical modeling of the steam chamber ramp-up phase in an SAGD operation. The steam chamber ramp-up phase was fully examined through the consideration of the effects of the temperature-dependent oil–water–gas multiphase flow system and the vertical countercurrent flow. The simulation results revealed that for the large temperature gradient of the mobile oil zone at the edge of the steam chamber, a delicate temperature-dependent multiphase flow system was essential for the reliable estimation of the SAGD ramp-up phase. The vertical countercurrent flows of oil–gas and oil–condensate were the dominant mechanisms over cocurrent flow, which significantly impacted the steam chamber ramp-up rate. The numerical model physically predicted the steam chamber ramp-up phase and could be used to efficiently compute a field-scale simulation using a dynamic gridding function that was based on a fine grid model.

Separate-effect drainage tests in a core make-up tank

Passive safety systems are widely used in the advanced nuclear reactors, such as AP1000 and CAP1400. As an important component in the passive safety system, the core make-up tank (CMT) plays a key role for the safety injection and the core decay heat removal. Although the structure of the CMT system is simple, it involves many thermal-hydraulic phenomena, most of which significantly impact the peak temperature of the fuel cladding and the liquid level of the core. Since the CMT not only provides full-pressure injection but also triggers the auto depressurization system by its liquid level signal during small-break loss of coolant accident (SBLOCA), its thermal hydraulic behaviors significantly affect the performance of the passive core cooling system (PXS). Therefore, separate effect tests are inevitable to verify the feasibility of CMT applied to passive safety and injection systems and to study its operating characteristics. In this work, a separate-effect CMT test facility was designed and constructed. Experiments were performed to investigate the CMT's thermal hydraulic characteristics under the effects of system pressure, steam condensation, and flow friction. The study found that the delay drainage phenomenon is the result of a pressure balance between the pipe line and the gravity head. Whether delayed drainage occurs depends on the degree of subcooling of the fluid at the top of the CMT. The flowrate is not affected by the heat transfer coefficient of steam direct contact condensation. The flow friction of the drainage pipeline has no effect on the delayed drainage process, but has a great influence on the gravity drainage process.

Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process

Gravity can reduce the instability of the gas-oil contact that is caused by gas channeling in locations with low flow resistance, such as high-permeability layers, macropores, and fractures during the gas-assisted gravity drainage process. Herein, the microscopic forces during the gas-assisted gravity drainage process were analyzed and combined with the capillary model to study the occurrence boundary of gas-assisted gravity drainage process, and the characteristics of the gas-oil contact in the gas-assisted gravity drainage process was discussed. The results show that free gravity drainage occurs only in pores where a certain height of the oil column and pore radius are reached. Furthermore, the lower the oil-gas interface migration rate, the easier free gravity drainage occurs. In other scenarios, additional gas injection is required. During the gas-assisted gravity drainage process, the gas-oil contact moves down stably as a transition. The width of the transition zone and the available pore radius are related to the gas-oil contact migration rate and the oil viscosity; the smaller the gas-oil contact migration rate and the lower the oil viscosity, the smaller pore throat can be involved in mobilization. Optimizing the gas injection rate and reducing the oil viscosity can delay the gas channeling maturity time, which is beneficial for the realization of the gas-assisted gravity drainage process. Finally, a method considering micropore heterogeneity is established for determining the critical gas injection rate, while the mainstream pore throat can be involved in mobilization and the gas-oil contact can be stabilized at the same time. The method of determining the critical gas injection rate can help researchers and reservoir engineers to better understand and implement the gas-assisted gravity drainage process. Cited as: Kong, D., Gao, J., Lian, P., Zheng, R, Zhu, W., Xu, Y. Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process. Advances in Geo-Energy Research, 2022, 6(2): 169-176. https://doi.org/10.46690/ager.2022.02.08

Evaluation of the effects of homogenizing matrix block sizes on the simulation of naturally fractured reservoirs

A vast amount of recoverable oil is buried in naturally fractured reservoirs. Due to the heterogeneous nature of matrix and fracture systems, there are many complexities in the simulation and production of these kinds of reservoirs. Fractures in naturally fractured reservoirs may be caused by various natural factors such as tectonic forces. Fracture distribution does not have a systematic pattern in naturally fractured reservoirs, and fractures are scattered across the formation. For the sake of simplicity, uneven distribution of fractures is not completely considered within practical reservoir simulation methodologies such as the commonly used dual-porosity approach. Using the dual-porosity methods, naturally fractured reservoirs are divided into simulation cells consisting of several matrix blocks. Against the nature of naturally fractured reservoirs, in the dual-porosity method, the fractures are often uniformly spread throughout the entire reservoir, and the sizes of matrix blocks inside the simulation cells are considered equal. For many years the assumption of homogenized matrix blocks in simulation cells has been used in the industry without proper evaluation of its effect on simulation results. This work examines the assumption of uniform matrix block size on the simulation results of naturally fractured reservoirs. An approach was proposed to create a simulation cell with randomly distributed matrix blocks to mimic the actual condition of naturally fractured reservoirs. Furthermore, realistic simulation approaches were utilized to investigate the oil recovery factor of different non-homogenized simulation cells during gravity drainage and imbibition processes. Also, the recovery factor performances of non-homogenized simulation cells were compared with simulation cells with uniform matrix block sizes created with different homogenization methods. An examination of the results revealed that a significant amount of inaccuracy in the simulation results could be caused by homogenization. Moreover, two types of homogenization approaches were used. In the first approach, a simulation cell with homogenized matrix block sizes based on the arithmetic mean of variable size matrix blocks was built. Homogenized matrix blocks in the second approach were built according to the arithmetic mean size of matrix blocks in different x, y, z directions. The first homogenization method resulted in less error compared to the second one. As compared with the gas invaded zone, simulation results of the water invaded zone are more error-prone. The findings of this work can help for better understanding the homogenization effect and prove that disregarding the heterogeneity of matrix blocks may lead to severe errors in the simulation results of naturally fractured reservoirs. The outcome also highlights the need for a more precise modeling and simulation approach for naturally fractured reservoirs.

A coupled model for predicting thermophysical properties of saturated steam in dual-tubing SAGD horizontal wells with toe-point injection technique

In this paper, a coupled numerical model to simulate dual-tubing steam-assisted gravity drainage (SAGD) process with toe-point injection technique was developed, specially, a more rigorous approach was used to calculate the steam pressure. Based on the model, the distribution of thermophysical properties of steam along the wellbore is investigated. The results indicate that improving the annulus steam temperature uniformity in circulation stage and the annulus steam quality uniformity in production stage is the key to enhancing the reservoir heating uniformity. The influence of the heat transfer from the wellbore to the reservoir on reservoir heating is significant with a low steam injection rate, but the influence is weak with a high steam injection rate. The reservoir temperature nonuniformity is more likely to occur during production stage than during circulation stage, and more attention needs to be paid to optimizing the reservoir temperature uniformity during production stage. A “toe-good” heating effect can be observed with toe-point injection technique, and simultaneous dual-tubing injection technology is a suitable method for solving this problem. The findings of this study can help to better understand the relationship between the distribution of thermophysical properties of saturated steam along the wellbore and reservoir nonuniform heating.

Coupling of steam chamber and liquid pool during steam-assisted gravity drainage process in heavy oil reservoirs

The flow mechanism between the injector and producer is different from the flow in the steam chamber in the Steam-Assisted Gravity Drainage (SAGD) process. The interwell flow between the injector and producer is determined by both gravity and the pressure difference. In this study, the interwell flow model is improved by introducing a relative permeability model and an oil viscosity linearity assumption, considering the availability of input data. The interwell flow in the liquid pool is coupled with the gravity drainage in the steam chamber throughout the entire SAGD process. And the liquid level calculated by the new model is validated by field data. The results show that the subcool gradient is larger in the earlier stage and smaller in the later stage. The liquid level, subcool, pressure difference and wellbore liquid rate are interacted and should be matched to each other. In field applications, the subcool should be controlled differently according to its development stage. The subcool of the hottest spot should be near zero to maximize the well productivity and the steam chamber supply capacity. The results of this study provide theoretical guidance for the evaluation and adjustment of field dual-horizontal SAGD well pairs.

Analytical and numerical study of thermal and solvent-based gravity drainage for heavy oil recovery

With the increasing demand for energy, an initial screening for heavy oil recovery options is important. However, the calculation of the gravity drainage recovery of heavy oil is complex and involves coupled fields and changes in the properties of heavy oil or its mixtures. There is currently no general analytical treatment for heavy oil gravity drainage processes, such as steam-assisted gravity drainage (SAGD), vapor extraction (VAPEX) and warm VAPEX, with the simplest possible assumptions but with the necessary mechanisms. In this study, a novel discrete hypothetical model has been proposed to simplify the calculation of gravity drainage flow in porous media. Then, a validated equation with a reasonable mixing rule is used to describe the property changes of heavy oil or its mixtures under decoupled temperature and concentration variables. Finally, internal velocity distributions for different gravity drainage processes are validated with numerical modeling results. Our results agree with previous work on the importance of mass transfer coefficients. Moreover, different from the previous work, the effect of slightly water-soluble solvents (dimethyl ether) has been investigated on diffusion in both the oil phase and the water phase. For solvent-based heavy oil recovery, a slightly water-soluble solvent shows great advantages with promising application potentials. The results of this study can guide the initial screening for a gravity drainage process and the analysis of its key mechanisms.

Bench-scale oil fouling/antifouling tests under high temperature and high pressure conditions and the underlying interfacial interaction mechanisms

Oil fouling is commonly encountered in many environmental and engineering fields and remains a challenging issue. The fouling issue in steam-assisted gravity drainage (SAGD) process for extracting bitumen from oil sands deposits has received much attention from oil industry. In view of low capital investment and exceptional antifouling performance, adding antifoulants has emerged as a promising strategy for addressing fouling issues. Developing an efficient method to evaluate their antifouling performance under production conditions is urgently needed. In this work, we report a novel bench-scale test method for quantitatively evaluating the antifouling performance of antifoulants under high temperature and high pressure (HTHP), close to SAGD operation conditions. The effects of antifoulant dosage and stirring rate on the antifouling performance are systematically investigated. The underlying fouling and antifouling mechanisms are characterized through direct molecular and surface force measurements. It is found that the commercial antifoulant exhibits exceptional antifouling performance at the dosage range of 20–35 ppm, and increasing stirring rate enhances the antifouling behavior. The force measurement results indicate that the antifoulant can adsorb to organics and target substrate surfaces, performing the antifouling function by lowering the hydrophobic interaction between organics and target substrates. This work provides a novel and feasible method for characterizing fouling phenomena and evaluating antifoulants under HTHP conditions and improves the understanding of fundamental interaction mechanisms underlying the fouling and antifouling phenomena.