bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Confinement and Well Interference on SAGD Performance - An Analytical Assessment
Authors: Zargar Zeinab , Ali S. M.
Published: February 2018

An analytical approach is introduced, for the first time, to evaluate the effect of confinement and well interference on SAGD process and achieve a better understanding of the situation. In this stage of SAGD, adjacent chambers interfere, the effective height for oil drainage decreases and heat loss rate decreases or in a conservative design remains constant. The objectives are to predict; oil production rate, steam injection rate, thermal efficiency, steam chamber velocity, unsteady temperature profile, heat distribution, and Cumulative Steam-Oil Ratio (CSOR). In this approach, heat transfer is coupled with fluid flow. The governing equations are; Darcy's law, volumetric balance, heat conduction, constitutive equations indicating the temperature dependence of some physical properties. The model is developed based on a moving boundary problem.
A New PVT Apparatus for Automatic Measurement of Foamy Oil Generation and Stability
Authors: Luo Peng , Li Sheng , Knorr Kelvin D. , Nakutnyy Petro
Published: February 2018

Cyclic solvent injection (CSI)—a non-thermal process option for development of post-CHOPS (cold heavy oil production with sand) heavy oil reservoirs—works by dissolving a gaseous solvent, mainly Methane (CH4) or Carbon Dioxide (CO2), and sometimes along with Propane or Butane into the in-situ heavy oil. A foamy oil is generated in-situ and produced during the production cycle due to pressure depletion. The generation and stability of foamy oil are considered important contributing factors to increased recovery from both solution gas drive and viscosity reduction mechanisms. This study used an innovative automatic flow loop apparatus to study questions about the pressure and gas type/concentration window for foamy oil generation and stability. The flow loop was applied to accurately monitor these phenomena through a number of property measurements at continuous flow conditions. Fluids inside the apparatus were automatically flowed back and forth between two upright Isco syringe pumps controlled by a LabVIEW data aquistion and control interface. The live oil in the system was depressurized either instantaneously or at a certain pressure drawdown rate to initiate foamy oil. Then, constant-volume pressure rebound (CVPR) tests and constant-pressure volume expansion (CPVE) tests were conducted, while density, viscosity, volume, and quality of the foamy oil phase were automatically measured and logged. The test results obtained with two separate gases, CH4 or CO2, revealed several fundamental mechanisms of foamy oil behaviour. Foamy oil stability was shown to be a complex function of live oil properties, solution/injection gas type, pressure drawdown rate, and shear rate. In the CVPR tests, when crude oil was saturated with CH4 or CO2 at the same bubblepoint pressure, the same pressure depletion decrement resulted in higher rebound pressure and longer time reaching stabilization for CH4 than CO2, due to slower CH4 bubble nucleation and release from the foamy oil phase. By contrast, the CPVE tests showed that the volume and viscosity increase ratio of the foamy oil phase compared to the original live oil were strongly affected by depletion pressure and drawdown rate. This indicates that, during a CSI process, there is an optimized window of pressure depletion rate and decrement that creates stable foamy oil at non-equilibrium conditions.
Steps Toward Designing the Optimum Outflow Control Device for SAGD using Computational Fluid Dynamics Simulation
Authors: Li Lei , Ma Yongsheng , Mahmoudi Mahdi , Fattahpour Vahidoddin , Lange Carlos F.
Published: February 2018

Effective steam distribution in the injector is the key to achieve efficient and uniform reservoir heat up in SAGD operation. The focus of this research is on simulating the flow dynamics in outflow control device (OCD), the annular space between the liner and tubing, the slots, and the gap between the slotted liner and formation, using computational fluid dynamics (CFD). The objective is to use the approximated metamodel to optimize the OCD design and achieve more even steam distribution through the slots.

A CFD model of the steam is developed through a systematic investigation of different domain sizes to study the effect of the pressure drop across the nozzle and the steam distribution. An evenness factor is proposed to quantify the overall steam distribution and to identify problematic slot areas. Based on the developed model, the OCD design is simplified and parameterized to conduct optimization efficiently. With the CFD expert system for steam simulation, the robust simulation models corresponding to different designs are obtained, providing accurate simulation results to the optimization algorithm. Using metamodeling, the response to the five design variables is derived, and the optimum is obtained subsequently. A cylindrical region representing the vicinity of the liner is added to the periphery of the slots to translate the optimization results into the realistic design.

The CFD simulation and OCD design optimization show that the steam distribution is highly controlled by the OCD design, mainly by the nozzles’ distance to the central plane. The novel evenness factor provides a quantitative assessment of the effect of design changes and it enables the application of advanced design optimization algorithms. Fifty-five numerical experiments are conducted to obtain the relationship between the proposed evenness factor and the design variables. The overall design of the OCD can be fine-tuned to account for the steam distribution. At the beginning of the heating cycle, some flow reversal is found in some specific slots, which may lead to sand production, plugging and erosion. When the distance between the two sets of nozzles is extended to 50 mm, the normalized evenness factor shows that the steam distribution can be improved by 12.5% from the original design in which the distance used to be zero. Moreover, the velocity magnitudes in the reverse flow affected region are also reduced in the optimized design.

The CFD simulation is a powerful tool to understand the flow dynamics through OCDs. This study applies a robust CFD model to investigate the complex flow interactions that affect steam distribution through OCDs to improve their design and thus to improve the steam distribution. The provided model and the design optimization algorithm could ultimately improve the heating efficiency.
Analysis of Heat and Mass Transfer Characteristics at the Chamber Interface for Solvent Assisted SAGD Process
Authors: Liu Hao , Cheng Linsong , Huang Shijun , Chen Xiao , Huang Qian
Published: February 2018

Co-injection of solvent and steam in Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) increases the mobility of highly viscous oil relative to conventional SAGD wherein only steam is injected. This consequently results in higher oil production rates and lower energy consumption relative to SAGD due to the combined benefits of heating and dilution. Current efforts have been made to study mass transfer from a single-component-solvent/steam mixture into the heavy oil at the steam front, while the low-cost multicomponent solvent is actually co-injected with steam on the field, which presents a much more complicated interfacial condition.

In this paper, a generalized methodology has been developed to couple heat and mass transfer of this solvents–steam–heavy oil system at the interface. In the model, the equation of state and fugacity equation are integrated to calculate and analysis the equilibrium state of transition interface. Then, the transition interface model is established based on heat transfer formulations and gaseous phase convective equations. Finally, under the temperature and velocity boundaries, the model is solved by applying implicit Runge-Kutta method and the results are used to analysis the heat and mass transfer characteristics.

The predicted results show that increasing the fraction of lighter solvent can enhance mass transfer, while the heat transferred is seriously deteriorated. Besides, the closer the bubble point temperature and dew point temperature of the stream is, the smaller the elevation of mass transfer will be, but the heat transfer is almost unaffected. Therefore, to realize the best effects of heat and mass transfer, solvents with larger saturation temperature difference should be applied, and the composition of the solvents should be carefully determined according to the formation properties and solvent components.

Conducting an ES-SAGD project on a field has many challenges, especially considering its main economic factors: production increase and solvent cost. With the new methodology, an optimum multicomponent solvent can be screened from the ocean of solvent candidates for a best heat and mass transfer performance in an ES-SAGD process and hence the oil flux at the chamber edge can be maximized with a minimized solvent cost. Therefore, it is of fundamental and practical importance to study the coupled heat and mass transfer of multicomponent solvents–steam–heavy oil system at the interface.
Heavy Oil Recovery Mechanisms by Surfactant, Polymer and SP in a Non-Linear System
Authors: Guerrero F. , Bryan J. L , Kantzas A.
Published: February 2018

The aim of this work is to evaluate the micro-displacement mechanisms associated with heavy oil recovery by water and chemical flooding in a non-linear system (2D Model). To evaluate the effect of sweep efficiency improvements with no local pore level trapping of fluids, a 2D neutral water wet Hele-Shaw cell is used to visualize the dominant mechanisms of surfactant, polymer and their combinations to enhance heavy oil recovery. Waterfloods were conducted as a base line, and compared to surfactant, polymer and SP floods at different injection stages (secondary and tertiary) and under variable injection rates. Post-breakthrough oil recovery and pressure drop during the water flood and chemical flood were evaluated with the analysis of images which show the distribution of the fluids in the cell.

The results demonstrated that in waterflooding, oil pinches off the pre-formed water fingers and allows the formation of snap-off which divert further water to un-swept zones. Oil is produced discontinuously because of snap-off effects, with production of oil related to small pressure spikes in the system. This mechanism was also observed in polymer displacements. This observation can explain viscous flow of oil and discontinuous oil and water production after breakthrough in a heavy oil waterflood. Oil stripping and zones of low IFT, in the form of O/W emulsions were mechanisms observed in surfactant and SP flooding. Such emulsions are present in secondary fingers that then propagate and sweep new areas of the cell. The synergy between polymer and surfactant leads to a slightly better sweep efficiency in the cell by stripping oil and stabilizing the flood front compared to surfactant or polymer alone. Injection rate has also an impact in the flow stability and formation and flow of emulsions. At higher injection rates, flow is more unstable and leads to a less oil recovery. Multiple tests under the same conditions revealed the reproducibility levels of each displacement process.

The novelty of this study is that it provides insights into fluid flow behavior in diverging flow paths as observed in 2D systems, as opposed to linear core floods that have limited flow pathways. In particular, these visual observations help to illustrate the role that surfactants can play in heavy oil systems, with and without the addition of polymer.
Direction of Wormhole Growth Under Anisotropic Stress
Authors: Oldakowski K. , Sawatzky R. P.
Published: February 2018

The CHOPS process involves the growth of high permeability channels (wormholes) into the reservoir. The wormholes provide improved access to the reservoir, thereby substantially increasing oil production rates. As production from a group of CHOPS wells matures, wormhole networks that have developed from different wells often interconnect. This can have negative consequences. For example, water influx into one well will spread readily to a system of interconnected wells.

A better understanding of preferential trends in the development of wormhole networks could allow more optimal placement of CHOPS wells, in terms of their spatial distribution. There are several factors that could influence the direction of wormhole growth in a heavy oil reservoir. The direction of growth may be affected by heterogeneity in the distribution of petrophysical and fluid properties such as permeability, porosity, water saturation, and oil viscosity. The stress field could be another factor.

This paper presents the results of an experimental investigation on the influence of anisotropic (unequal) horizontal principal stresses on the direction of wormhole growth in a sand pack saturated with viscous oil. The experiments were performed in a large rectangular triaxial cell (box). Each of the two perpendicular horizontal stresses and the vertical stress applied to the sand pack could be controlled independently. Oil was injected into the sand pack through flow distributors located on adjacent vertical walls of the cell. The oil flowed through the sand toward a production well in the cell. When a critical flow rate was reached, the sand failed around one of the openings in the well. The failed sand was transported by the oil into the well, resulting in the growth of a wormhole inside the pack.

The experiments indicated that, under the conditions of stress and flow that were applied, there was a tendency for wormholes to grow in the direction of the lower horizontal stress. However, this tendency was overcome when there were significant directional differences in the oil flux (pressure gradient). Then, the wormholes tended to grow in the direction of the largest oil flux. Both behaviours are consistent with the local effective stress conditions at the tip of a wormhole that lead to continuing sand failure there.
Integration of Data-Driven Models for Characterizing Shale Barrier Configuration in 3D Heterogeneous Reservoirs for SAGD Operations
Authors: Ma Zhiwei , Leung Juliana Y.
Published: February 2018

Shale barriers may act as flow barriers with adverse impacts on the steam chamber development, as observed in numerous field-scale SAGD projects. Efficient parameterization and inference of such heterogeneities in 3D models from production data remain challenging. A novel workflow for SAGD heterogeneity inference by integrating data-driven modeling and production time-series data analysis is presented.

Variation of shale barriers along the directions between the cross-well pair, as well as of the horizontal wellbore, is considered. Based on a dataset gathered from the public domain, a set of reservoir and operational parameters that represent the typical Athabasca oil sands conditions are extracted to build a 3D homogeneous (base) model. The heterogeneous models are constructed by superimposing shale barriers with varying volume, geometry and locations onto the base model. Production data is recorded by subjecting the generated models to numerical simulation. Input features are extracted from the production time-series data, while output parameters are formulated based on the distribution of shale barriers in the generated models. Data-driven models, such as artificial neural network (ANN), are applied to approximate the non-linear relationships between input and output variables, facilitating the inference of shale characteristics. The final outcome is an ensemble of 3D models of heterogeneity that honor the actual SAGD production histories.

A decline in oil production is observed when the steam chamber encounters a shale barrier. The proposed workflow can capture the observed production patterns effectively. The proposed methodology is demonstrated to be useful for characterizing shale heterogeneities. A testing dataset is used to assess the consistency between model predictions and the target values. In addition, the production responses corresponding to the characterized heterogeneous models are in agreement with the actual responses.

Previous data-driven modeling studies involving 3D heterogeneity inference and SAGD production analysis are limited. The issue of parameterizing a large number of possible heterogeneity descriptions is still challenging. This work presents a preliminary effort to explore this issue. It offers a significant potential to extend most widely-adopted data-driven modeling approaches for practical SAGD production data analysis. The outcomes serve to support the use of data-driven models as complementary and computationally-efficient tools for inference of shale barriers.
Assessment of Methods for Evaluating VIT Thermal Performance
Authors: Damour Jean-Aurelien , Orberg Frederico , Johannson Darren
Published: February 2018

For a completion where Vacuum Insulated Tubing (VIT) is requested, the thermal performance is one of the key parameters to select the fit for purpose product. The heat loss of a VIT string depends not only on the VIT design, but also on external parameters such as effluent and annular fluid temperature and composition, making it difficult to provide the intrinsic thermal performance of the VIT. The industry doesn't have any codes or standards describing a method to evaluate this thermal performance. This paper presents a comparison of the main thermal test methods used by VIT suppliers and operators and sets the limitations of some of these methods. It also proposes a novel method to evaluate VIT thermal performance.

Most thermal tests are realized either on VIT joints in a workshop or on a VIT completion run in a well. The principle is the use of sensors (i.e. temperature gauge, optical fiber or heat flux meter) to provide information on the temperature gradient that could be linked to the heat losses based on some assumptions on the heat exchange coefficient with the external environment. In the study, these thermal test methods are assessed with a finite elements analysis software, which enables the simulation of the different evaluation methods and their comparison by using the same VIT design.

The study stresses how the details of each thermal test procedure and the assumptions made has an impact on the thermal performance it gives. In particular, the location of the sensors or the fluid considered outside the VIT will provide different thermal performance results when varying. A thermal test method is proposed and assessed with the same software in several simulated environments.

This study shows the difficulties to evaluate the VIT thermal performance on the same basis with different factors that could vary, like the test location (inside, outside or in a well), the sensors location and the test conditions (temperature, external fluid being a gas or a liquid). The study also proposes a new thermal evaluation methodology and assesses it with the same criteria used to analyze the main test methods used in the industry.
Longitudinal Dispersion Coefficient in Consolidated Porous Media; A Pore-Level Study
Authors: Mohammadmoradi Peyman , Kantzas Apostolos
Published: February 2018

The fluid flow and transport phenomena are simulated through three-dimensional consolidated and unconsolidated digital rock slabs representing the geological rock types of the McMurray formation. Finite element simulations are carried out in order to solve the mixing advection-diffusion problem, and the effluent history is processed to predict the longitudinal dispersion coefficient and evaluate the efficiency of miscible displacement processes in the presence of microheterogeneities. According to the results, consolidated samples with non-uniform cementation show a different dispersion behavior when compared to both unconsolidated and uniformly cemented rocks, suggesting that the cementation pattern remarkably influences the miscible-flood performance.
Case History-Utilizing Dual Wellhead SAGD in Alshachinskoe Heavy Oilfield in Tartarstan, Russia
Authors: Nukhaev Marat , Rymarenko Konstantin , Latfullin Azat , Amerhanov Marat
Published: February 2018

For decades it has been known that there are several techniques for heavy oil recovery, including traditional Steam Assisted Gravity Drainage (SAGD), cross-well SAGD, single well SAGD, and horizontal alternate steam drive (HASD) etc. The main purpose for these techniques are incresasing efficiency of the SAGD process and controlling steam chamber development.

In this paper, case history will be shared in regards to, implementing for the first time a new method of SAGD techniues in the Alshachinskoe heavy oil field. Based on the results of several trial wells, the proposed dual wellheads SAGD scheme provides the following advantages over traditional SAGD: (1) less risk during drilling and completion phase, (2) more uniform preheating phase provided by several injection points, and (3) more possibility for steam chamber development control during production phase.

As a result the average production for heavy oil was increased from 2 tonnes per day for vertical wells to 24 tonnes per day for dual wellheads SAGD technology (with maximum daily production up to 63 tonnes). The average steam-oil-ratio for dual wellheads SAGD is around 3 (sm3/sm3), that proves high efficiency of the method for steam chamber development and steam trap control over entire period of wells life time.
Feasibility of SAGD as a Follow-Up Process to CSS for a Massive Deep Bitumen Reservoir
Authors: Wu Yi , Wang Zhongyuan , Han Bing , Li Xiaoman , Zhou Guangxing , Wang Ziji
Published: February 2018

Steam Assisted Gravity Drainage (SAGD) is a widely used thermal recovery method for heavy oil and bitumen. S-13832 reservoir in Liaohe oil field in China is reaching economical limit after several cycles of cyclic steam stimulation (CSS). To improve the recovery, toe-to-heel air injection (THAI) had been field tested, however with unfavorable results. In this study, we analyze the alternative SAGD process and show it as most promising follow-up for CSS in S1-3832 reservoir.

We first conduct comprehensive summary of reasons for the previous THAI trial failure, including lack of knowledge for shale layer distributions, difficulties in control spreading of combustion front and blockage of wellbore. Then, numerical simulation has been performed to investigate the feasibility and advantage of using SAGD process in S1-3832. A fine-grid reservoir model with shale layers carefully characterized for reservoir heterogeneity and oil-water distributions modeled. Finally, history match of the field is carried out and dominant influencing factors for SAGD recovery were determined in order to establish an optimum reservoir development strategy.

Vertical injector-horizontal producer and vertical injector-vertical producer hybrid well configuration is adopted in the type pattern simulation model. Key parameters such as perforation locations, steam quality, production-injection ratio, injection rate and SAGD transition time are optimized. It is observed that steam chamber shape is irregular due to the presence of shale layers in some locations. Based on shale layer characteristics of the reservoir, perforation positions together with injection and production rates are adjusted to improve the conformance in these areas. According to these findings, a practical development strategy is designed. Ultimately, the simulation results show the production rate, accumulative oil-steam ratio and other indicators satisfy the requirement of economic development, with incremental recovery factor of 39%in the SAGD stage.

The optimum development plan has been successfully implemented for more than 1 year now, with monitored temperature showing steam chamber growth in favorable manner in the entire reservoir, even in area above shale barriers. With thermal communication achieved, production rate increases progressively, indicating a smooth transition to SAGD mode. This work has demonstrated SAGD as effective recovery process in S1-3832. It also provides technical guidance for designing follow-up processes to CSS for similar reservoirs.
Azeotropic Heated Vapour Extraction- A New Thermal-Solvent Assisted Gravity Drainage Recovery Process
Authors: Khaledi Rahman , Motahhari Hamed Reza , Boone Thomas J. , Fang Chen , Coutee Adam S.
Published: February 2018

Thermal-Solvent Assisted Gravity Drainage processes are heavy oil recovery processes in which the stimulation mechanism for bitumen viscosity reduction is by heating and dilution. The range of the injected solvent concentration with steam may be low such as in Solvent Assisted-SAGD or very high such as in Heated Vapour Extraction. The performance behaviour of these processes is significantly driven by the complex thermodynamic interaction of steam and solvent, heat transfer, multiphase fluid equilibrium and flow in the porous medium.

ExxonMobil and its affiliate Imperial have been optimizing the existing recovery processes and developing new technologies to improve the efficiencies and environmental performance of the heavy oil production operations. Recent focus has been on developing thermal-solvent based recovery processes through an integrated research program that includes fundamental laboratory work, advanced numerical simulation studies, laboratory scaled physical modeling, and field piloting. The research program aims at in-depth investigation and understanding of process physics and mechanisms, and evaluating process performance and behaviour to enable development of new recovery methods and to enhance the performance.

This paper focuses on the fundamental concepts of Azeotropic Heated Vapour Extraction, a new thermal solvent recovery technology developed by ExxonMobil-Imperial. This technology takes the combined advantages of the solvent dilution mechanism for enhanced oil production rate with the minimum required energy (GHG emission), as well as the effectiveness of energy transport of steam to minimize the required solvent in circulation for the extraction process. In this paper, the complex solvent-steam phase behaviour and reservoir fluid flow and their interaction under operating conditions are investigated. The analysis of experimental and modeling data shows that the injection of solvent-steam mixture at its azeotropic condition results in significant improvement in process key performance indicators (KPI's). At these conditions, the reservoir is heated to the minimum boiling temperature of the solvent-steam mixture compared to a Heated VAPEX or Solvent Assisted-SAGD process resulting in the reduction of the required energy thereby minimizing the solvent-to-oil ratio. Also, due to phase equilibrium, the vaporization of in-situ water is prevented resulting in the reduction of retained solvent in the depleted zone of the reservoir. It is found that an improvement in the process KPI's is dependent on the volatility of the selected solvent. The process KPI's also vary with operational conditions. The recovery process is optimized for certain reservoir constraints through the selection of the solvent boiling range and consequently the azeotropic steam content in the injected mixture.
Screening Surfactants for Application in SAGD – Including a Steam-phase Coreflood Test
Authors: Jonasson Ralph G. , Imran Muhammad , Knorr Kelvin D.
Published: February 2018

This research sought to determine whether surfactants and other steam additives can further improve oil recoveries in steam-assisted gravity drainage (SAGD), and to identify plausible mechanisms. It involved extensive experimental study and method development to screen the surfactants suitable for high temperature application and to evaluate incremental improvements in bitumen recovery using surfactants in the gas phase. Formulations of several surfactants were prepared to optimize their properties (e.g., cost, performance, partitioning, water solubility).

The types of surfactants selected for this study were sulfonates and pyrrolidones. These surfactants were pre-screened according to thermal stability in water, interfacial tension (IFT), contact angle, and formation water compatibility. The selected surfactants were tested using the specially designed steam soak apparatus to evaluate the transport of surfactants in the steam phase to the gas/bitumen interface. Linear hot water and steam corefloods in different configurations were also performed to investigate the oil recovery mechanism associated with the use of high temperature surfactants. High-performance liquid chromatography (HPLC) was used to measure surfactant concentrations for thermal stability and coreflood testing.

The steam-soak tests did reveal that combining N-octyl-2-pyrrolidone (NOP) with a sulfonate surfactant, alkyldiphenylethersulfonate (ADPES), could substantially improve oil recovery. This was dispite the fact that sulfonates are not volatile in steam. The hot-water corefloods showed an upward trend in oil recovery with an increase in the N-alkyl-2-pyrrolidone molecular weight and boiling point. The steam corefloods showed the highest recovery for surfactant mixture with 1000 mg/kg NOP and 500 mg/kg ADPES. The post-run core images showed cleaner sand indicating the incremental recovery from the use of surfactant mixture was being achieved by producing the residual oil from the steam chamber. NOP is miscible with bitumen, and is capable of dissolving asphaltenes. However, the viscosity data of oil treated with NOP suggests that viscosity reduction due to surfactant/additive addition is probably not the primary mechanism responsible for improved recoveries. Rather, it can be attributed more towards the IFT reduction, wettability alteration or surfactant dispersion of bitumen in water. No tight bitumen-in-water emulsions were produced in any of the tests.
Produced Water Ammonia Removal using RO Membrane Process
Authors: Chen Cheng , Heimel Sandra , Young Patric
Published: February 2018

This paper presents a novel technology for simultaneous removal of boron and ammonia using two-pass RO membranes for operational cost reduction in produced water treatment. While various conventional technologies exist to remove ammonia from water, they tend to require large capital investments. Examples include ammonia stripping, activated sludge processes, breakpoint chlorination of ammonia, and ion exchange technology. This technology solves a problem of simultaneously removing boron and ammonia from produced water in a cost-effective manner. With the deployment of this technology in Chevron’s San Ardo produced water treatment plant, approximately $1,500,000 in annual OPEX saving is expected while keeping compliance with the plant Waste Discharge Requirement (WDR) permit.
Numerical Simulation of Dielectric Heating in a Heavy Oil Reservoir Using a Shaped Dipole Antenna
Authors: Ovalles Cesar , Vaca Pedro , Okoniewski Michal , Dieckmann Gunther , Pasalic Damir , Dunlavey James
Published: February 2018

The numerical evaluation of dielectric heating in a heavy oil containing sand is presented using a shaped dipole antenna under static (no oil production) and dynamic (with oil production) conditions. The electromagnetic simulator AxREMS™ was coupled to the commercial reservoir simulator STARS™ to model RF heating using three different shaped antenna designs (Straight dipole, Concave, and Convex design). The static simulations showed that the Concave design offers more uniform radiation pattern and temperature profile than the Straight and Convex counterparts. A conceptual model with seven sands (over- and under-burden and five oil-containing sands) was utilized for the dynamic simulation of downhole RF dielectric heating. The results indicated that all the RF heating cases had accelerated oil production than that found for the Base Case (cold production). Modeling shows that peak production is increased if RF heating is initiated before the start of production. However, all cases studied converged to approximately equal cumulative incremental oil above the Base Case, after about 700 days after the initiation of RF heating.
An Experimental Investigation into Sand Control Failure Due to Steam Breakthrough in SAGD Wells
Authors: Mahmoudi M. , Fattahpour V. , Roostaei M. , Kotb O. , Wang C. , Nouri A. , Sutton C. , Fermaniuk B.
Published: February 2018

In Steam Assisted Gravity Drainage (SAGD) projects, it is essential to heat the reservoir evenly to minimize the potential for the localized steam breakthrough. Steam breakthrough can cause erosive damage to the sand control liner by the flow of high-velocity wet steam, and, in extreme cases, can compromise the mechanical integrity of the liner. This research investigates the sanding mechanism during the high-quality steam injection into the SAGD production wells.

A large-scale Sand Retention Test (SRT) was used to investigate the role of steam breakthrough in the sand control performance. Produced sand and pressure drops along the sand-pack were the main measurements during the tests. The test procedure and test matrix were designed to enable the examination of the impact of steam breakthrough on sand production for different steam rates.

Two possible sanding mechanisms are postulated in steam breakthrough events: (1) local grain disturbance caused by the high-velocity steam near the liner, (2) effect of the complex phase behavior of the steam and the subcool level. Two different testing procedures were designed to examine these mechanisms. The local grain disturbance mechanism was investigated by injecting air at a wide range of velocities. Results indicate that this mechanism could not lead to a significant sanding when there is a bit of effective stress near the liner. Hence, it looks like that the steam velocity poses a higher risk in early stages of SAGD production when the near-liner stress is very low. The effect of high-pressure high-temperature (HPHT), low- to high-quality steam flow and the subcool level will be investigated in the next phase of the study. This work addresses the effect of high-quality steam breakthrough on the sand control performance of the liner in SAGD producer wells. The findings in this paper help the researchers to direct their research to better understand the steam breakthrough. This research will eventually help the engineers in their liner design and evaluation for the entire wellbore life cycle as the near-well stress evolves.
Geologically Consistent History Matching of SAGD Process Using Probability Perturbation Method
Authors: Khani Hojjat , Hamdi Hamidreza , Nghiem Long , Chen Zhangxing , Sousa Mario Costa
Published: February 2018

The overall objective of reservoir modeling is to reduce the uncertainty in production forecasts by utilizing all available data to construct a calibrated reservoir model. Geological heterogeneities have a fundamental impact on the growth of a steam chamber and the performance of a SAGD (steam assisted gravity drainage) process. The objective of this work is to incorporate geological heterogeneities into the history matching process using a probability perturbation method (PPM) to preserve the geological consistency of a reservoir model.

A PPM is a geological data integration framework which employs a multiple-point geostatistics (MPS) algorithm. The heart of this method is to systematically perturb the underlying probabilities used to generate the reservoir facies. A PPM generally consists of two loops: an outer loop which is responsible for randomly generating a global configuration of the facies and an inner loop which systematically perturbs the generated facies to match the dynamic data. The combination of these two iterations creates a set of realizations that preserve the geological information.

In this paper, a training image is built based on a 3D outcrop description of a meandering channelized reservoir that is analogous to some of the Canadian heavy oil reservoirs. All other available data including reservoir properties at well locations, trends and production data are also incorporated into the PPM framework for this history matching process. The reservoir model is characterized by three facies: clean sands, medium-grained sandstones and silts, which have different porosity, horizontal permeability and vertical permeability. The SAGD performance is a function of steam chamber development, which depends on the level of heterogeneity in the reservoir. The results show that the heterogeneity distribution has a large impact on the fluid flow at different stages of production. The results show that such complexities can be well preserved during the history matching process using the PPM by generating the geological patterns depicted in a training image. The PPM is shown to be an efficient approach for history matching in presence of complex reservoir geology.
A Critical Review of Sand Control Evaluation Testing for SAGD Applications
Authors: Montero J. D. , Chissonde S. , Kotb O. , Wang C. , Roostaei M. , Nouri A. , Mahmoudi M. , Fattahpour V.
Published: February 2018

This paper presents a critical review of current evaluation techniques for the selection and design of sand control devices (SCD) for Steam Assisted Gravity Drainage (SAGD) wells. With the industry moving towards exploiting more difficult reservoirs, there is a need to review the current testing methods and assess their adequacy for sand control evaluation for different operational and geological conditions.

In addition to a critical review of existing sand control testing approaches for SAGD, the paper also discusses the testing parameters in previous studies to evaluate their representativeness of the field conditions in terms of interstitial seepage and viscous forces, and flow geometry. Moreover, the paper reviews the analysis and results of sand control testing in the literature and assesses the sand control design criteria in terms of the level of acceptable sand production and plugging. Furthermore, the review evaluates the suitability of the sample size, sand preparation techniques, representation of the SCD in the testing, and experimental procedures.

The review shows variations in the existing sand control testing in SAGD, in terms of not only approach, sand control representation, and sample size, but also regarding operational test conditions, such as flow rates and pressures. Ideally, large-scale pre-packed tests that include the effects of temperature and radial flow geometry would more closely emulate the actual conditions of SAGD wells than most existing tests allow. High temperatures may affect sanding and plugging through changes in wettability, permeabilities, and mineral alterations. Further, the varying velocity profile in radial flow towards the SCD influences the fines migration pattern differently from the linear-flow conditions in the existing Sand Retention Tests (SRT). However, large-scale radial-flow tests are constrained by cost and complexity.

Most SRT experiments have employed high flow rates, exceeding the equivalent field rates. Utilizing realistic rates for the tests and appropriately capturing the actual fluids ratios, water cuts and steam breakthrough scenarios can improve the quality of testing data. Accordingly, existing SRT experiments can be designed to incorporate, if not all, but some of the relevant physics in SAGD by employing representative viscosities, flow rates, fluid properties and ratios, stress conditions and obtain suitable live and post-mortem measurements.

This critical review compiles various aspects of current sand retention tests and evaluates their applicability to SAGD well conditions. It serves as a starting point for future research by providing an overview of existing testing methods, highlighting the strengths and opportunities for improvements.
Nanoparticle Stabilized Solvent-Based Emulsion for Enhanced Heavy Oil Recovery
Authors: Kumar Ganesh , Kakati Abhijit , Mani Ethayaraja , Sangwai Jitendra Shital
Published: February 2018

The objective of this study is to develop a solvent-based Pickering emulsion stabilized by silica nanoparticle for enhanced heavy oil recovery. Unlike the light oil, the recovery of heavy oil is quite challenging because of its high viscosity. To reduce the viscosity of heavy crude oil, solvent-based Pickering emulsion is explored to improve the recovery of heavy oil. The approach is to use solvent-in-water emulsion stabilized by nanoparticle which is more economical as compared to thermal or solvent-based enhanced oil recovery (EOR) methods. In this work, the solvent-in-water Pickering emulsion has been prepared by homogenizing the mixture with the help of homogenizer at 13000 rpm for 3 minutes. It can be inferred from the experimental results that the use of nanoparticle has helped to improve the stability of solvent-based Pickering emulsion for a longer period of time as compared to conventional surfactant based emulsions due to irreversible adsorption of silica nanoparticle at the oil-water interface. The silica nanoparticle of 15 nm size is used to make the Pickering emulsion. The colloidal stability and surface charge of the nanoparticle is evaluated by zeta potential. Silica nanoparticle is expected to improve the rheological stability of solvent-based emulsion and provides favorable mobility. Hence, these solvent-based emulsion flooding can provide high displacement efficiencies like miscible solvent flooding and better sweep efficiency like polymer flooding and helps to improve the enhanced heavy oil recovery. The novelty of the nanoparticle stabilized solvent-based Pickering emulsion is that it can sustain harsh reservoir conditions and remains very stable for a longer period of time as compared to other EOR techniques. The droplet size of these emulsions is few micron in size so that it can easily flow through the pore throat size of the formation reservoir and helps in improving the enhanced heavy oil recovery.
Hydrocarbon Recovery Using a Convective Solvent Extraction Process
Authors: Sood Arun , Gupta Subodh
Published: February 2018

Going forward, limiting greenhouse gas emissions and reducing water usage in oil sands upstream operations is essential to meeting regulatory requirements and a pre-condition for the social license to operate. As Oil Sands Industry exhausts its best quality rich pay and gradually move into producing bitumen from marginal quality assets with thin pay zones, SAGD performance will deteriorate with higher steam to oil ratios. In this paper, Enhanced Convective Solvent Extraction (ECSOLVEX) process is described to apply to such reservoirs.

ECSOLVEX predominantly uses a pure solvent which is injected into the reservoir at or above its dew point temperature. Injection and production wells are placed some distance apart in the same lateral plane. Sidetracks from injector well to close proximity of the producer well allow a solvent chamber to extend to the inter-well region. The process is primarily gravity driven with a mild convective gradient from injector to the producer well. A solvent chamber is established along the side track lateral, which grows parallel to the injector and producer wells. Water production is limited since it is a solvent driven processthat would result in a reduced footprint for the surface oil water separation facility.

Simulation results show that each side track creates its own drainage chamber which performs independently of other drainage chambers till they merge, thus the production performance of this process is a function of the number of sidetracks drilled. As an example, with propane as the solvent, production rates can be doubled that of SAGD if sidetracks are drilled every 100m. The energy consumption and associated emissions of such a process would be 70% less than SAGD. The performance can be further improved by localized heating in the proximity of the producer well.

ECSOLVEX process concept provides the opportunity for economic recovery from pay zones which are not thick enough for traditional SAGD process to operate. It demonstrates significantly lower energy consumption as compared to SAGD, leading to a lower carbon footprint and has the potential to reduce the size of the oil water separation facility.
Analysis of Dynamic Imbibition Effect of Surfactant in Microcracks of Reservoir at High Temperature and Low Permeability
Authors: Xie Kun , Lu Xiangguo , Pan He , Han Dawei , Hu Guangbin , Zhang Ji , Zhang Baoyan , Cao Bao
Published: February 2018

The objective of this work was to explore the dynamic imbibition effect of a surfactant solution in the microcracks of a reservoir at high temperature (83.3°C) and low permeability (2 × 10−3 µm2), as well as the relative influencing factors. This study considered Fuyu Reservoir of the Toutai Oil Field in Daqing, China, which has high-temperature and low-permeability characteristics, as a research platform. First, the optimal surfactant type and concentration were selected by evaluating the imbibition recovery through a study of the adhesion-work-reduction factor and the ratio of the capillary force and gravity (NB−1), under the conditions of a spontaneous-imbibition experiment. Then, through a dynamic imbibition experiment, this study investigated the effects of the injection velocity, wettability, and saturation of the matrix on the dynamic imbibition recovery. Both the experimental results and practical application showed that the surfactant could effectively improve the imbibition recovery. However, in the process of choosing a surfactant, one must consider the influence of interfacial tension (IFT) on the capillary force when reducing the adhesion work to improve the displacement efficiency. A suitable injection velocity should be chosen to take full advantage of the ability of the capillary force to “absorb water and discharge oil,” as well as the “displacement function” of the viscous force and “improved wettability” provided by the surfactant, to obtain a higher imbibition recovery. Enhancing the water-wet state of matrix blocks can help to improve the seepage flow between the matrix and microcracks, which assists in increasing the imbibition recovery. Thus, a surfactant with an appropriate concentration or other chemical agents can be selected to enhance the water-wet state of matrix blocks. When a surfactant solution is used to develop a similar reservoir, earlier imbibition construction assists the capillary force to provide the function of “absorbing water and discharging oil,” which is helpful to enhance the imbibition recovery. The practical application of a surfactant solution in Well M38-S64 in the Mao 8 area showed that adding a surfactant to a water solution assists in improving the imbibition recovery.