White Papers and Research Articles

The RGL innovation strategy addresses the need for a greater scientific understanding of the challenges faced by the heavy-oil industry. Improving product performance and reducing uncertainty encourages capital investment, ensures healthy production rates, and improves overall production factors. These issues are as important to RGL’s success as they are to Canada’s economy.

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Corrosion and Scaling
2020

Authors: Lu Gong, Ling Zhang, Li Xiang, Jiawen Zhang, Vahidoddin Fattahpour, Mahdi Mamoudi, Morteza Roostaei, Brent Fermaniuk, Jing-Li Luo, and Hongbo Zeng

Surface interactions between emulsion drops and substrate surfaces play an important role in many phenomena in industrial processes, such as fouling issues in oil production. Investigating the interaction forces between the water-in-oil emulsion drops with interfacially adsorbed asphaltenes and various substrates is of fundamental and practical importance in understanding the fouling mechanisms and developing efficient antifouling strategies. In this work, the surface interactions between water drops with asphaltenes and Fe substrates with or without an electroless nickel–phosphorus (EN) coating in organic media have been directly quantified using the atomic force microscope drop probe technique. The effects of asphaltene concentration, organic solvent type, aging time, contact time, and loading force were investigated. The results demonstrated that the adhesion between water drops and the substrates was enhanced with higher asphaltene concentration, better organic solvent to asphaltenes, longer aging time, longer contact time, and stronger loading force, which was due to the growing amount and conformational change of asphaltenes adsorbed at the water/oil interface. Meanwhile, the adhesion between the water drop and the EN substrate was much weaker than that with the Fe substrate. The bulk fouling tests also showed that EN coating had a very good antifouling performance, which was in consistence with the force measurement results. Our work sheds light on the fundamental understanding of emulsion-related fouling mechanisms in the oil industry and provides useful information for developing new coatings with antifouling performances.

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2020

Authors: Chong Sun, Jiankuan Li, Vahidoddin Fattahpour, Morteza Roostaei, Mahdi Mahmoudi, Hongbo Zeng, Jing-Li Luo

The erosion-enhanced corrosion behavior of electroless Ni–P coating was investigated by single particle impingement coupled with in-situ electrochemical measurements. The transient anodic dissolution of Ni–P coating induced by the single particle impingement is enhanced with the rising impact velocity, followed by a rapid repassivation that obeys a bi-exponential decaying law. The coating demonstrates a good erosion-corrosion resistance due to its strong capability of repassivation that is scarcely affected by the changing hydrodynamics under the test conditions. The erosion-enhanced corrosion rate of Ni–P coating in flowing slurry is well predicted based on the repassivation kinetic parameters determined from single particle impingement.

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2020

Authors: Zhengbin Wang, Chong Sun, Linlin Li, Morteza Roostaei, Vahidoddin Fattahpour, Mahdi Mahmoudi, Hongbo Zeng, Yugui Zheng, Jing-Li Luo

Repassivation time (tre) is a significant parameter when evaluating the repassivation property of material. Herein, we propose a new method to obtain tre by first theoretically unifying the repassivation current–time (i(t)) function for common film growth models, subsequently simplifying the unified i(t) function based on single particle impingement data, then deriving the completed repassivation current expression corresponding to tre using mathematical approximation methods, and finally verifying this method via comparing the obtained tre of three materials. The newly proposed method is reliable, universal and simple to compare repassivation properties of different materials without curve fitting and considering film growth mechanism.

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2020

Authors: Jiankuan Li; Chong Sun; Morteza Roostaei; Mahdi Mahmoudi; Vahidoddin Fattahpour; Hongbo Zeng; Jing-Li Luo

The electrochemical corrosion behavior of Ni-P coating in 3.5 wt% NaCl solution-containing CO2 and H2S was investigated using electrochemical methods and surface characterization techniques. The results show that the presence of H2S can enhance the CO2 corrosion of Ni-P coated carbon steel by affecting both anodic and cathodic processes. The H2PO2 adsorbed layer only exists in the very early stage of corrosion and barely improves the anticorrosion performance of the coating. The formation of corrosion products (NiO and Ni3S2) renders temporary protection during immersion, but the addition of H2S accelerates the diffusion process at the electrolyte/coating interface and promotes the electrolyte penetration through the coating, causing severe localized corrosion and coating disbondment. A corrosion model is proposed to illustrate the corrosion and degradation process of Ni-P coated steel in the CO2/H2S/Cl environment.

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2020

Authors: Ali Habibi (University of Alberta) | Charles Fensky (Blue Spark Energy) | Mike Perri (Blue Spark Energy) | Morteza Roostaei (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ali Ghalambor (Oil Center Research International) | Mohtada Sadrzadeh (University of Alberta) | Hongbo Zeng (University of Alberta)


Previous studies showed that different parameters influence the plugging of completion tools. These parameters include (i) rock mineralogy, (ii) reservoir fluids properties, and (iii) type of completion tools. Although different methods have been used for unplugging these tools, there is still debate regarding performance of these methods on damage removal.

In this study, we assessed the performance of high-power shockwaves generated from an electro-hydraulic stimulation (EHS) tool on cleaning completion tools plugged during oil production. These devices were extracted from different wells in Canada, Europe, and the US. First, we evaluated the extent of cleaning for the plugged completion tools using an EHS tool at the lab-scale. We examined the slots/screens before and after the treatment to show the performance of the EHS tool. Next, we analyzed the mineral composition and morphology of the plugging materials removed after the treatment by conducting X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM), and Energy Dispersive X-Ray Spectroscopy (EDS) analyses. Finally, we reviewed the pulsing stimulation treatment results applied to several field case studies.

The results of unplugging sand control devices at the lab-scale showed that more than 50% of plugged slots/screens were cleaned after 45 pulses of shockwaves. The characterization results showed that the main plugging materials are calcite, silicate, and iron-based components (corrosion products). The results of field case studies showed an improved oil production rate after the pulsing stimulation treatment.

This paper provides a better understanding of the performance of shockwaves on damage removal from plugged completion tools. The results could provide a complementary tool for production engineers to select a proper method for treating the plugged tools.

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2020

Authors: Jiankuan Li, Chong Sun, Morteza Roostaei, Mahdi Mahmoudi, Vahidoddin Fattahpour, Hongbo Zeng, Jing-Li Luo


The electroless Ni-Mo-P/Ni-P composite coating was applied on N80 carbon steel, and the effects of Mo addition and heat treatment on the corrosion resistance enhancement in CO2/H2S/Cl brine were studied by electrochemical measurements and surface analysis techniques. The Mo addition in the as-deposited Ni-P coating causes the microstructural transformation from amorphous to crystalline due to the reduced P content, thereby suffering severe corrosion. The impaired corrosion performance of as-deposited Mo-incorporated coating is also originated from the absence of the oxide film on the coating surface. Nonetheless, the heat-treated Ni-Mo-P/Ni-P coating exhibits desirable corrosion resistance, which is reflected by the outstanding corrosion inhibition efficiency (η = 96.1%). Heat treatment facilitates the formation of Ni4Mo phase and more importantly, the growth of an oxide film consisting of nickel and molybdenum oxides (H2S-immuned MoO3) with better passivation properties, which accounts for the remarkable corrosion resistance improvement.

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2020

Authors: Ali Habibi (University of Alberta) | Charles Fensky (Blue Spark Energy) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Hongbo Zeng (University of Alberta) | Mohtada Sadrzadeh (University of Alberta)


Scale deposition and its treatment are crucial part of any thermal recovery method. High temperature variation, phase change associated with steam condensation and flashing, and complex flow dynamics of the wells make the thermal wells more susceptible to scale deposition. Several studies evaluated the type of scales collected from plugged sand screens; however, more investigation is required to address the reservoir conditions and wellbore hydraulics affecting the scaling potential of minerals at downhole conditions.

A laboratory workflow combined with a predictive modeling toolbox to evaluate scaling tendency of minerals for different downhole conditions has been developed. First, saturation indices (SI) for different minerals were calculated at reservoir temperature and pressure using water chemistry analysis and the Pitzer theory. Then, the mineral composition of deposited materials collected from thermal wells in Athabasca and Cold Lake area were characterized using Scanning Electron Microscopy (SEM), Energy Dispersive X-Ray Spectrometry (EDS), Total Organic Carbon (TOC) and Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses. Finally, a comparison analysis was performed between predictive and characterization results.

The results of SI calculations showed that Mg-based silicates and Fe-based minerals are positive (SI>5) even at high temperatures (T>430 K). This indicates that the possibility of deposition for these minerals is high. Carbonates (calcite and aragonite) minerals are the most common depositing minerals. However, the extent of scaling index of carbonates is controlled by the concentration of Ca, HCO3, and CO3 in the water sample. The characterization results confirm the results of modeling part. The results of SEM/EDS, ICP-MS analyses showed that carbonates, Mg-based silicates, and Fe-based corrosion products are the most common depositing materials among all minerals.

The workflow presented in this study will help the industry to evaluate the scaling potential for thermal wells at different downhole conditions to make a proper decision to prevent plugging of the completion tools.

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Artificial Intelligence
2020

Authors: Hossein Izadi, Javad Sadri, Fateme Hormozzade, Vahidoddin Fattahpour


Intelligent mineral segmentation in thin section images of rocks still remains a challenging task in modern computational mineralogy. The objective of the paper is segmenting minerals in geological thin section’s images with special attention on altered mineral segmentation. In this paper, an efficient incremental-dynamic clustering algorithm is developed for segmentation of minerals in thin sections containing altered and non-altered minerals. In the clustering algorithm, there is no need for determining the number of clusters (minerals) existed in thin section images, and also it is able to deal with color changing and non-evident boundaries in altered minerals. We have solved two main existing limitations: segmentation of mineral pixels that are frequently labeled as background pixels, and segmentation of thin sections containing altered minerals. Moreover, we created an open database (Alborz Mineralogical Database), as a benchmark database in computational geosciences regarding image studies of mineral. The proposed method is validated based on the results provided by the segmentation maps, and experimental results indicate that the proposed method is very efficient and outperforms previous segmentation methods for altered minerals in thin section images. The proposed method can be applied in mining engineering, rock mechanics engineering, geotechnique engineering, mineralogy, petrography, and applications such as NASA’s Mars Rover Explorations (MRE).

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2019

Authors: Izadi, Hossein & Fattahpour, Vahidoddin & Roostaei, Morteza & Mahmoudi, Mahdi & Devere-Bennett, Noel.


Particle size distributions (PSDs) plays an important role in designing sand control screens. Using different techniques (Dry Sieving, LPSA, and Dynamic Image Analysis (DIA)), large number of PSDs could be measured for core samples in a certain project. Moreover, large-scale sand retention tests are becoming common practice in recent years. These tests usually use duplicated sand mixtures of representative PSDs. Therefore, clustering the PSD data is essential for sand control design and sand retention tests. Supervised and unsupervised machine learning algorithms are getting more attention in computational petroleum engineering. Usually there is no clear idea that how many clusters are supposed to be detected in each PSD database. Therefore, due to the limitation for setting the number of clusters, PSD clustering could not be accomplished using conventional clustering algorithms such as k-means or artificial neural networks. As a new approach, PSD clustering based on an incremental clustering algorithm is used here. The proposed algorithm has online incremental learning capability and it is based on adaptive resonance theory (ART). Besides, the number of clusters is not needed to be assigned as an input parameter in the algorithm. The algorithm, based on a self-adaptation approach, tries to minimize the number of clusters. Accordingly, it is appropriate for PSD clustering of big databases. The proposed algorithm can be used in industrial applications such as sand control design and sand control evaluation testing.

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Flow Control Engineering
2019

Authors: Giuseppe Rosi (RGL Reservoir Management) | Da Zhu (RGL Reservoir Management) | Dermot O'Hagan (Suncor Energy)


Inflow Control Devices (ICDs) have been adopted for commercial steam-assisted gravity drainage (SAGD) production for nearly ten years and yet the function they serve is not well understood, and field data evaluating their performance remains scant. Thus, the purpose of the current study is twofold: Firstly, the study derives a simplified analytical model demonstrating how increasing the dP across ICDs acts to improve conformance along a producing lateral. The resulting equation of the analysis acts as a simple rule of thumb for determining an appropriate pressure drop across ICDs to achieve conformance. Secondly, the study evaluates the performance of ICDs that had been installed in four wells, two of which had ICDs installed prior to circulation and two that adopted ICDs later in their lifecycle. The field data shows that ICDs increase production rates and improve conformance along the lateral. These improvements are achieved by an increased drawdown facilitated by the ICDs. This part of the study highlights how early-life results may differ between ICD bearing wells compared to their conventionally completed (slotted liner) offsets: ICD bearing wells exhibit improved conformance and an ability to develop more challenging reservoir resulting in different oil production profiles and composite SORs.

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2017

Authors: Marty Lastiwka (Suncor Energy) | Chris Bailey (Suncor Energy) | Bruce James (Suncor Energy) | Da Zhu (RGL Reservoir Management)


Over the past few years, an increasing number of operators in steam assisted gravity drainage (SAGD) in situ recovery of bitumen in the Alberta Oil Sands are becoming interested in the use of flow control devices (FCDs). Initial field trials by some operators of these devices have shown promise in improving steam chamber conformance, reducing incidences of steam breakthrough, high vapour production, and in addressing liner reliability concerns related to steam jetting.

While the application of FCDs is well-established in the conventional oil and gas industry to control gas and water coning, there are still a number of questions on how to implement FCDs optimally in SAGD. One major difference in the application of FCDs in SAGD compared to the conventional oil and gas industry is the high temperature environment with steam and elevated erosion risk.

The purpose of this paper is to present some practical considerations for the selection of FCDs and optimal completion FCD design for SAGD applications. In the first section, a discussion is presented on how to compare the performance of different flow control devices. Most devices have not been tested for SAGD, and there is a need for more comprehensive testing. The focus of the second section is on practical considerations for the installation of FCDs in a SAGD injection and production wells.


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2017

Authors: Da Zhu (RGL Reservoir Management Inc.) | Ian D. Gates (University of Calgary)


Given the high viscosity of the oil, bitumen from oil sands reservoirs in western Canada is recovered by using steam which, due to its temperature, lowers its viscosity. One of the key issues faced by the operators is the steam conformance of the depletion chamber around wells. The greater the fingering phenomena of steam at the edge of chamber, the worse is the chamber uniformity and utilization of the well, and the greater are the green house gas emissions and water use per unit oil recovered. Fingering has long been explained as the penetration of steam phase into the oil phase which arises from an unfavourable mobility ratio. In this paper, we introduce linear instability analyses (Orr-Sommerfeld and Rayleigh-Taylor/Saffman-Taylor instability) of the interface between steam and oil layers and conduct a series of numerical simulations to reveal that fingering in the steam-assisted heavy oil recovery at the top of the steam chamber is created due to solution gas exsolution whereas fingering at the chamber edge is due to viscous shear instability. The results show that non-ideal steam conformance is inevitable even in homogeneous reservoirs.


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2016

Authors: Da Zhu (RGL Reservoir Management Inc.) | Gary Bunio (Suncor Energy) | Ian D. Gates (University of Calgary)

The main challenges faced by oil sands operators are the cost of operations and the environmental intensity of the recovery processes. The Athabasca oil sands deposit contains bitumen with viscosity typically over 1 million cP. To lower the viscosity of the bitumen so that it can be drained from these reservoirs, it is heated with injected steam by using Steam-Assisted Gravity Drainage (SAGD). This process is effective and enables recovery factors over 60%. The major cost in the recovery process is steam generation and associated water treatment and handling. The combustion of natural gas to generate steam is the main origin of the carbon dioxide emissions associated with SAGD. An alternative to steam injection is the use of solvents co-injected with steam. Solvents dilute bitumen leading to an oil phase with reduced viscosity. Also, there is potential to recycle solvent for re-injection. Thus, solvent added to steam can improve the steam-to-oil ratio and as a consequence can lower the carbon dioxide emissions per unit volume oil produced. In this extended abstract, we describe a phased solvent and heat process that yields improved performance beyond that of SAGD and current solvent-aided SAGD processes.


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2016

Authors: Da Zhu (RGL Reservoir Management Inc.) | Jacky Wang (University of Calgary) | Yi Su (University of Calgary) | Ian D. Gates (University of Calgary)

Numerical simulators have been extensively used in reservoir engineering for several decades. These simulators, based on energy, material, and momentum (multiphase Darcy law) balances and thermodynamic equilibrium of components between phases, solve a coupled set of nonlinear partial differential equations. We have observed multiple states for simulation of Steam-Assisted Gravity Drainage (SAGD) with multiple steam-to-oil ratios resulting at the same steam injection rate. The existence of multiple solutions and potentially limit cycle behavior and its associated bifurcation branching in the operation parameter space inspires us to consider a dynamical approach to reservoir simulation. There are four dominant states of stability: absolutely stable; neutrally stable; unstable subject to infinitesimal perturbation; and unstable subject to finite amplitude perturbation. In essence, instability is a process that releases potential energy stored in the base state to the perturbation state. In a reservoir simulation, if we impose a perturbation with a certain magnitude to a quasi-steady state, linear stability theory predicts that once the system becomes unstable, the magnitude of the perturbation grows with time infinitely. However, in reality, due to nonlinearity the system causes it to evolve to a new quasi-steady state. The questions that we are going to address in this paper are: How can we use a transient reservoir simulator to detect instability of the system that may lead to different and multiple operating states? As a case study, we will use a 2D homogeneous SAGD model. Once the model reaches a quasi-steady state, we will call it our base state. Then we impose different steam injection rate perturbations on the system and see how the system responds to these changes. Different behaviors result –for finite amplitude perturbations, the state evolves to a new state (Hopf bifurcation) (Strogatz 2014). Our goal is to use an existing commercial simulator to construct multiple operating states and describe an approach to detect them. Multiple operating states could have significant implications for process control and risk/uncertainty management of reservoir operations.


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Downhole Monitoring
2020

Authors: Soroush, Mohammad & Mohammadtabar, Mohammad & Roostaei, Morteza & Hosseini, Seyed Abolhassan & Fattahpour, Vahidoddin & Mahmoudi, Mahdi & Keough, Daniel & Tywoniuk, Matthew & Cheng, Li & Moez, Kambiz. (2020).


Effective Steam Assisted Gravity Drainage (SAGD) operation relies on subcool management to reduce the risk of steam breakthrough. Monitoring of several parameters is performed to assure uniform development of steam chamber and heating of reservoir. This paper discusses the application of Distributed Acoustic Sensing (DAS), a monitoring platform to achieve reliable reservoir and wellbore surveillance in SAGD projects.

In this study, a comprehensive review of DAS deployment in oil and gas industry was performed including vertical seismic profiling, hydraulic fracturing, well/pipe integrity and flow profiling applications. Then, SAGD flow monitoring was investigated in detail. To utilize DAS in SAGD projects, knowing completion designs are necessary. Therefore, various SAGD completion designs and corresponding flow regimes were discussed as well. Finally, four flow loop designs were proposed to accurately simulate the complex wellbore hydraulics of the SAGD producer using DAS recordings.

This work started with an overview of DAS systems in downhole monitoring including real time high resolution vertical seismic profiling, hydraulic fracturing characterization and optimization, well and pipe integrity, leak detection and assessing completion effectiveness. Then, flow profiling including flow rate, flow fractions and flow regimes determinations using DAS were discussed with focus on SAGD monitoring. Completion designs directly impact on SAGD monitoring and DAS recordings, more specifically on flow regimes inside the tubing and annulus. Therefore, various completion designs with their tubing and screen sizes were presented and corresponding flow regimes were determined in both tubing and annulus. It was observed that flow regimes vary with type of completion design, liquid flow rate, steam breakthrough locations and tubing/screen sizes. Eventually, four flow loop designs were proposed based on the discussions for future DAS application.

This paper discusses existing completion designs and possible flow regimes in SAGD projects. Consequently, novel designed flow loops are introduced for DAS deployment to better understand the complex wellbore hydraulic of the well and measure the key parameters in optimizing the production operation. This study is a design stage for future quantitative measuring of flow profiling using DAS systems.


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2019

Authors: Mohammad Soroush (RGL Reservoir Management, University of Alberta) | Morteza Roostaei (RGL Reservoir Management) | Vahidoddin Fattahpour (RGL Reservoir Management) | Mahdi Mahmoudi (RGL Reservoir Management) | Daniel Keough (Precise Downhole Services Ltd) | Li Cheng (University of Alberta) | Kambiz Moez (University of Alberta)


Accurate prediction of flow regime and flow profile in wellbore is among the main interests of production engineers in the quest of optimizing wellbore production and increasing reliability of downhole completion tools especially in SAGD projects. This study introduces a methodology for wellbore monitoring by detecting flow phase and flow regime. In order to develop this method, an advanced multi-phase flow injection experiment was designed and commissioned.

A flow injection setup was developed to test distributed fiber optic sensor installation under different operating conditions, including multi-phase flow (oil, brine and gas), and flow fraction scenarios. Different signal processing methods were applied to extract meaningful features and filter the noise from the raw signals. A statistical analysis was performed to assess the trend of the driven data. Then, typical SAGD models were simulated to assess the results of experimental setup for scale-up purpose and determination of local breakthrough of steam along the well.

Results showed that the Distributed Acoustic Sensing (DAS) data contains different levels of signals for each phase and flow regime. We also found that some level of uncertainties is involved in relating the flow regime and DAS information which could be resolved by improving the sensor installation procedure. In addition, the application of data-driven machine learning methods was found necessary to interpret the signal patterns. Initial results have shown that steam breakthrough along the well can be detected using real time DAS high energy/frequency signals. It can be concluded that including the DAS along with Distributed Temperature Sensing (DTS) is necessary to provide a better picture of steam conformance and SAGD wellbore monitoring. The limitations of the current experimental setup restricted further conclusions regarding the hybrid DAS and DTS application.

This paper is a part of an ongoing project to address the application of the combined DAS and DTS in SAGD projects. The ultimate goal is a downhole monitoring system to oversee the flow phase, flow regime and sand ingress in thermal application. The next phase will address the required improvements for developing a flow loop to handle high temperatures, include sand production and mimic thermal operation conditions.


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Experimental Flow Modelling
2020

Authors: Shadi Ansari (University of Alberta) | Reza Sabbagh (University of Alberta) | Yishak Yusuf (University of Alberta) | David S. Nobes (University of Alberta)


Studies that investigate and attempt to model the process of steam-assisted gravity drainage (SAGD) for heavy-oil extraction often adopt the single-phase-flow assumption or relative permeability of the moving phases as a continuous phase in their analyses. Looking at the emulsification process and the likelihood of its prevalence in SAGD, however, indicates that it forms an important part of the entire physics of the process. To explore the validity of this assumption, a review of prior publications that are related to the SAGD process and the modeling approaches used, as well as works that studied the emulsification process at reservoir conditions, is presented. Reservoir conditions are assessed to identify whether the effect of the emulsion is strong enough to encourage using a multiphase instead of a single-phase assumption for the modeling of the process. The effect of operating conditions on the stability of emulsions in the formation is discussed. The review also covers the nature and extent of effects from emulsions on the flow mechanics through pore spaces and other flow passages that result from the well completion and downhole tubing, such as sand/flow-control devices. The primary outcome of this review strengthens the idea that a multiphase-flow scenario needs to be considered when studying all flow-related phenomena in enhanced-oil-recovery processes and, hence, in SAGD. The presence of emulsions significantly affects the bulk properties of the porous media, such as relative permeability, and properties that are related to the flow, such as viscosity, density, and ultimately pressure drop. It is asserted that the flow of emulsions strongly contributed to the transport of fines that might cause plugging of either the pore space or the screen on the sand-control device. The qualitative description of these influences and their extents found from the review of this large area of research is expected to guide activities during the conception stages of research questions and other investigations.


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2020

Authors:  &  


The interactions of the bubbles in a loosely packed bubbly flow in a high viscous fluid approaching a pore space are studied using a shadowgraph imaging technique. The motion of the bubbles has been evaluated by considering shape analysis of their deformation and the variation in the velocity and pressure distribution of the phase. A comparison of two cases of a linear array and a matrix of bubbles emphasizes the importance of the arrangement on the deformation and motion of the dispersed phase in the pore space. The deformation of the bubbles in both cases results in a deceleration and acceleration process of the dispersed phase in the pore region. This process was a function of size, number of the bubbles competing in the pore throat and the arrangement of the competing bubbles. The variation in the motion of the dispersed phase will ultimately lead to different flow motion and phenomena at the entrance of the pore throat. The results also highlight that although bubbles had different motion approaching the pore throat, they follow similar deformation transition as they enter and exit the pore throat. This work contributes to existing knowledge of multi-phase flow in pore space by providing further understanding the effect of the interaction of phases based on the arrangement and their motion in a porous geometry.


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2020

Authors:  &  


An in-situ measurement technique to determine the rheology of a fluid based on the experimentally measured velocity profile of a flow in a mini-channel is introduced. The velocity profiles of a Newtonian and different shear-thinning fluids along a rectangular channel were measured using shadowgraph particle image velocimetry (PIV). Deionized water and different concentrations of a polyacrylamide solution were used as Newtonian and shear-thinning fluids, respectively and were studied at different Reynolds numbers. The flow indices of the fluids were determined by comparing the experimental velocity profile measurements with developed theory that takes into account the non-Newtonian nature of the fluids rheology. The results indicated that the non-Newtonian behavior of the shear-thinning fluid intensified at lower Reynolds numbers and it behaved more as a Newtonian fluid as the Reynolds number increased. A comparison between the power law index determined from experimental monitoring of the velocity profile at different Reynolds numbers and measurements from a rheometer reflected good agreement. The results from the study validate the new approach of the rheology measurement of Newtonian and non-Newtonian flows through straight, rectangular cross-section channels. The proposed approach can be further utilized using other methods such as X-ray PIV to characterize the rheology of non-transparent fluids and in general, for all non-Newtonian fluids.


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2020

Authors:


The flow of dispersed gas bubbles in a viscous liquid can create a bubbly, slug bubble, or elongated bubble flow regime. A slug bubble flow, characterized by bubble sizes equal to the hydraulic diameter of the channel, is a transition regime with a complex local flow field that has received little attention in the past. In this study, dynamics of this flow regime in a square capillary with a cross-sectional area of 3 × 3 mm² was studied analytically and experimentally. The main geometric parameters of the flow field, such as film and corner thicknesses and volume fraction, were calculated for different flow conditions based on a semi-empirical approach. Using velocity fields from particle image velocimetry (PIV), combined with the analytical equations derived, local mean variations of the film and corner flow thicknesses and velocity were analyzed in detail. Analysis of the results reveals a linear relation between the bubble speed and the liquid slug velocity that was obtained using sum-of-correlation PIV. Local backflow, where the liquid locally flows in the reverse direction, was demonstrated to occur in the slug bubble flow, and the theoretical analysis showed that it can be characterized based on the bubble cross-sectional area and ratio of the liquid slug and bubble speed. The backflow phenomenon is only contributed to the channel corners, where the speed of liquid can increase to the bubble speed. However, there is no evidence of reverse flow in the liquid film for the flow conditions analyzed in this study.


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Sand Control Evaluation
2020

Authors: Yujia Guo, Alireza Nouri, and Siavash Nejadi

Sand production from a poorly consolidated reservoir could give rise to some severe problems during production. Holding the load bearing solids in place is the main goal of any sand control technique. The only sand control techniques that have found applications in steam assisted gravity drainage (SAGD) are some of the mechanical methods, including wire wrapped screens, slotted liners and more recently, punched screens. Slotted liner is one of the most effective mechanical sand control methods in the unconsolidated reservoir exploitation, which has proven to be the preferred sand control method in the SAGD operations. The main advantage of the slotted liners that makes them suitable for SAGD operations is their superior mechanical integrity for the completion of long horizontal wells. This study is an attempt to increase the existing understanding of the fines migration, sand production, and plugging tendency for slotted liners by using a novel large-scale scaled completion test (SCT) facility. A triaxial cell assembly was used to load sand-packs with specified and controlled grain size distribution, shape and mineralogy, on multi-slot sand control coupons. Different stress levels were applied parallel and perpendicular to different combinations of slot width and density in multi-slot coupons, while brine was injected from the top of the sand-pack towards the coupon. At each stress level, the mass of produced sand was measured, and the pressure drops along the sand-pack and coupon were recorded. Fines migration was also investigated by measuring fines/clay concentration along the sand-pack. The current study employed multi-slot coupons to investigate flow interactions among slots and its effect on the flow performance of liner under typically encountered stresses in SAGD wells. According to the experimental observations, increasing slot width generally reduces the possibility of pore plugging caused by fines migration. However, there is a limit for slot aperture beyond which the plugging is not reduced any further, and only a higher level of sanding occurs. Test measurements also indicated that besides the slot width, the slot density also influences the level of plugging and sand production and must be included in the design criteria.


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2020

Authors: Jesus David Montero Pallares (University of Alberta) | Chenxi Wang (University of Alberta) | Mohammad Haftani (University of Alberta) | Alireza Nouri (University of Alberta)


Wire-wrapped screens (WWSs) are one of the most-commonly used devices by steam-assisted gravity drainage (SAGD) operators because of the capacity to control plugging and improve flow performance. WWSs offer high open-to-flow area (OFA) (6 to 18%) that allow a high release of fines, hence, less pore plugging and accumulation at the near-screen zone. Over the years, several criteria have been proposed for the selection of aperture sizes on the basis of different industrial contexts and laboratory experiments. Generally, existing aperture-sizing recommendations include only a single point of the particle-size distribution (PSD). Operators and academics rely on sand-control testing to evaluate the performance of sand-control devices (SCDs). Scaled laboratory testing provides a straightforward tool to understand the role of flow rate, flowing phases, fluid properties, stresses, and screen specifications on sand retention and flow impairment.

This study employs large-scale prepacked sand-retention tests (SRTs) to experimentally assess the performance of WWSs under variable single-phase and multiphase conditions. The experimental results and parametric trends are used to formulate a set of empirical equations that describe the response of the WWS. Several PSD classes with various fines content and particle size are tested to evaluate a broad range of PSDs. Operational procedures include the coinjection of gas, brine, and oil to emulate aggressive conditions during steam-breakthrough events.

The experimental investigation leads to the formulation of predictive correlations. Additional PSDs were prepared to verify the adequacy of the proposed equations. The results show that sanding modes are both flow-rate and flowing-phase dependent. Moreover, the severity or intensity of producing sand is greatly influenced by the ratio of grain size to aperture size and the ability to form stable bridges. During gas and multiphase flow, a dramatic amount of sanding was observed for wider apertures caused by high multiphase flow velocities. However, liquid stages displayed less-intense transient behaviors. Remarkably, WWSs rendered an excellent flow performance even for low-quality sands and narrow apertures. Although further and more complete testing is required, empirical correlations showed good agreement with experimental results.


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2020

Authors: Morteza RoostaeiAlireza NouriVahidoddin Fattahpour and Dave Chan


This paper focuses on the study of proppant transport mechanisms in fractures during frac-packing operation. A multi-module, numerical proppant, reservoir and geomechanics simulator has been developed, which improves the current numerical modeling techniques for proppant transport. The modules are linked together and tailored to capture the processes and mechanisms that are significant in frac-pack operations. The proposed approach takes advantage of a robust and sophisticated numerical smeared fracture simulator and incorporates an in-house proppant transport module to calculate propped fracture dimensions and concentration distribution. In the development of software capability, the propped fracture geometry and proppant concentration, which are the output of the proppant module, are imported to the hydraulic fracture simulator through mobility modification. Complex issues of proppant transport in fractures that are addressed in the literature and captured by the current model are: hindered settling velocity (terminal velocity of proppant in the injection fluid), the effect of fracture walls, proppant concentration and inertia on settling (due to extra drag forces applied on particles, compared to single-particle motion in Stokes regime in unbounded medium), possible propped fracture porosity and also mobility change due to the presence of proppant, and fracture closure or extension during proppant injection. A sensitivity analysis is conducted using realistic parameters to provide guidelines that allow more accurate predictions of the proppant concentration and fluid flow. The main objective of this study is to link a numerical hydraulic fracture model to a proppant transport model to study the fracturing response and proppant distribution and to investigate the effect of proppant injection on fracture propagation and fracture dimensions.

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2020

Authors: Chenxi Wang, Yu Pang, Mahdi Mahmoudi, Mohammad Haftani, Mahmoud Salimi, Vahidoddin Fattahpour, Alireza Nouri

Slotted liners have been widely used in steam-assisted gravity drainage (SAGD) wells owing to their low cost and superior mechanical integrity. Multiple factors affect the performance of slotted liners, such as particle size distribution (PSD) of formation sands, aperture size, slot density, fluid flow rate, and wellbore operational conditions. Currently, most of the existing design criteria formulate the lower and upper bounds of the aperture based on one or several points on the particle size distribution curve of oil sands. Most of these design criteria neglect the slot density, wellbore operational conditions, and shape of PSD curve.

This study carries out a series of large-scale pre-pack sand retention tests (SRT) in step rates. The aim is to investigate the impacts of aperture size, slot density, and fluid flow rate on the slotted liner performance. Comprehensive design criteria for determining the safe aperture window are presented to maintain the sanding and the wellbore plugging of the zone near the slotted liners within an acceptable level. Sand production governs the upper bound of the aperture size, and flow performance guides the lower bound of the aperture size. The new criteria are presented graphically to illustrate the optimal slot window as a function of the sand PSD, slot density, and fluid flow rate. The results of separate tests are used to demonstrate the performance of the new design criteria. The optimal slot window obtained via the new design criteria guides the slot liner selection in the SAGD process.

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2020

Authors: Morteza Roostaei (RGL Reservoir Management Inc.) | Alireza Nouri (University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Arian Velayati (University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

 

 

Final proppant distribution inside hydraulic fractures which depends on particle properties, movement and deposition highly impact wellbore productivity and consequently is crucial in modeling and design of hydraulic fracturing. This paper presents a thorough review of laboratory scale tests performed on proppant transport related to hydraulic fracturing treatments and governing physics behind its mechanisms.

The interaction between fluid (gas and liquid) and solid particles has been investigated in applied mathematics and physics. In such phenomena, there is always a relative motion between particles and fluids. In this work this relative motion during proppant movement, sedimentation and fluidization in both small- and large-scale lab tests have been assessed in detail. Existing correlations which relate proppant particles settling velocity to concentration of proppant particles, fracture wall and inertia effect in Newtonian and non- Newtonian fluid are presented as well.

Lab tests show that various parameters determine the proppant particles distribution inside the fractures. Particle settling velocity, an influential parameter in this regard, is impacted by fracture walls, inertia and the presence of other particles. Inertia changes the relation of drag coefficient and Reynold number. Fracture wall and particles concentration decrease settling velocity as drag force increases. At a certain level, concentration reaches to its limit. Proppant concentration, in addition, increases the suspension viscosity, fracture width and net pressure. However, it deceases the fracture length as more pressure loss occurs along the fracture. As a result, well productivity is highly impacted by the proppant settling and distribution.

Many studies have been devoted to identifying different aspects of hydraulic fracturing and proppant transport mechanisms in porous media. This study highlights the key parameters and their effects, existing correlations and physics behind them for better understanding and management of this mechanism.

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2020

Authors: Chenxi Wang, Jesus D. Montero Pallares, Mohammad Haftani, Alireza Nouri

Stand-alone screens (SAS) have been widely used in steam assisted gravity drainage (SAGD) operations. Although many researchers investigated the flow performance of SAS through sand control tests, the formation damage (pore plugging) due to fines migration has not been characterized under multi-phase flow conditions. In this study, a methodology is developed to quantify and characterize the fines migration under multi-phase flow sand control testing conditions.

A large-scale sand retention test (SRT) facility is used to investigate the flow performance of SAS. Duplicated sand samples with similar particle size distribution (PSD), shape, and mineralogy properties to the McMurray Formation oil sands are obtained by mixing different types of commercial sands, silts, and clays. Oil and brine are simultaneously injected into the sand-pack at different water-cut levels and liquid rates to emulate the changing inflow conditions in SAGD operations. The saturation levels in each flow stage are measured to determine the relative permeability values. Next, the relative permeability curves of the duplicated sand-pack sample are measured following the steady-state method. Finally, the pressure data obtained from the SRT in each flow stage are coupled with the relative permeability values to calculate the retained permeability as the indicator of flow performance of SAS'.

Generally, testing results show that single-phase oil flow generates minor and negligible permeability impairments in the near-screen zone of the sand-pack. An evident permeability reduction is observed once the water breakthrough happens, indicating that the wetting-phase fluid significantly mobilizes fine particles and causes pore plugging. Also, with the increase of flow rate and water cut, a further reduction in permeability is found as a result of the higher drag force and greater exposure area of fines to brine.

The proposed methodology presented in this study allows quantitative characterization of the formation damage under multi-phase flow condition and provides a practical and straightforward method for the evaluation of the SAS's flow performance.


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2020

Authors: Siavash Taghipoor, Morteza Roostaei, Arian Velayati, Atena Sharbatian, Dave Chan, Alireza Nouri

This paper presents a numerical investigation of hydraulic fracturing in oil sands during cold water injection by considering the aspects of both geomechanics and reservoir fluid flow. According to previous studies, the low shear strengths of unconsolidated or weakly consolidated sandstone reservoirs significantly influence the hydraulic fracturing process. Therefore, classical hydraulic fracture models cannot simulate the fracturing process in weak sandstone reservoirs. In the current numerical models, the direction of a tensile fracture is predetermined based on in situ stress conditions. Additionally, the potential transformation of a shear fracture into a tensile fracture and the potential reorientation of a tensile fracture owing to shear banding at the fracture tip have not yet been addressed in the literature. In this study, a smeared fracture technique is employed to simulate tensile and shear fractures in oil sands. The model used combines many important fracture features, which include the matrix flow, poroelasticity and plasticity modeling, saturation-dependent permeability, gradual degradation of the oil sands as a result of dilative shear deformation, and the tensile fracturing and shear failure that occur with the simultaneous enhancement of permeability. Furthermore, sensitivity analyses are also performed with respect to the reservoir and geomechanical parameters, including the apparent tensile strength and cohesion of the oil sands, magnitude of the minimum and maximum principal stress, absolute permeability and elastic modulus of the oil sands and ramp-up time. All these analyses are performed to clarify the influences of these parameters on the fracturing response of the oil sands.


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2020

Authors: Yanlong LiFulong NingNengyou WuQiang ChenAlireza NouriGaowei HuJiaxin SunZenggui KuangQingguo Meng

The process of extracting natural gas from gas hydrate‐bearing sediments (GHBS) may yield significant sand influx due to the metastable nature of GHBS. Selecting appropriate sand control media is vital to addressing the challenges caused by excessive sand production. This study proposes a protocol called holding coarse expelling fine particles (HCEFP) for sand control design. The protocol aims to provide a new optimization method for screen mesh size selection for clayey silt hydrate reservoirs. Detailed optimizing procedures of proper candidate screen mesh sizes in hydrate exploitation well in clayey silt hydrate reservoirs are depicted based on the HCEFP. Then, the site W18, which is located in the Shenhu area of the northern South China Sea, is taken as an example to illustrate the optimization procedure for screen mesh size selection. The results reveal that complete solid retention via a standalone screen is rarely beneficial as high clay contents can adversely affect wellbore productivity due to excessive plugging. Screen aperture size selection for clayey silt hydrate wells should strike a balance between retaining coarser particles and avoiding screen blockage by the relatively fine particles. Furthermore, longitudinal heterogeneity of the PSDs also increases the difficulties associated with sand control design. Multistage sand control optimization is necessary in hydrate production wells. For Site W18, we recommend that the entire production interval can be divided into two subintervals for multistage sand control operations.


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2020

Authors: M. HaftaniO. KotbP. H. NguyenChenxi WangMahmood SalimiAlireza Nouri

Optimum design of the sand control devices in oil sand reservoirs plays a vital role in minimizing the sand production and increasing the reservoir productivity in Steam-Assisted Gravity Drainage (SAGD) operations. Various sand control testing facilities have been developed to evaluate the performance of sand control screens, such as the pre-packed Sand Retention Test (SRT). Current testing apparatuses are based on the linear flow regime. However, fluid flow around SAGD production wells is radial flow, not linear. This study introduces a Full-scale Completion Test (FCT) facility to emulate the radial-flow condition in SAGD wells. Instead of using a disk-shaped screen coupon, this facility utilizes a cylindrical-shaped screen. A couple of tests were carried out to determine the flow uniformity inside the cell and identify the test repeatability. Test results show that flow is distributed uniformly inside the cell, and experiments are repeatable in terms of differential pressures, fines production, and sanding levels. Therefore, this innovative FCT experimental setup and procedure allows a more realistic evaluation of the liner performance by emulating the real SAGD flow regime around the liner. Testing results obtained from the FCT can be used to complement and validate the current testing procedures. These tools can be adopted for an objective custom-design and selection of standalone screens in SAGD. 


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2020

Authors: Morteza Roostaei (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Arian Velayati (University of Alberta) | Ahmad Alkouh (College of Technical Studies) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


Sieve analysis, sedimentation and laser diffraction have been the methods of choice in determining particle size distribution (PSD) for sand control design. However, these methods do not provide any information regarding the particle shape. In this study, we introduce the application of Dynamic Image Analysis (DIA) to characterize particle sizes and shape descriptors of sand bearing formations.

Dynamic Image Analysis, an advanced method of particle size and shape characterization, along with other PSD measurement methods, including sieving combined with sedimentation, and laser diffraction, was utilized to study size and shape variations of 372 unconsolidated formation sand samples from North America, Latin America, and the Middle East. Different methods were compared for the estimation of PSD and fines content, which is important for sand control design.

Through minimizing the sampling and measurement errors, the deviation between different PSD measurement techniques was attributed solely to the shape of the particles and the amount of fine fraction. For fines content measurement, the values obtained through Feret Min. parameter values (the minimum size of a particle along all directions) calculated by DIA and sieving measurement are comparable within a 5% confidence band. The deviation between the results of different methods becomes more significant by increasing fines content. Moreover, this deviation increases for less isodiametric grains. The fines and clay content show higher values when measured by any wet analysis. Laser diffraction also tends to overestimate the fines fraction and underestimate silt/sand fraction compared to other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed which chooses the equivalent sphere sizes of DIA with minimum deviation from sieving.

This study performs several measurements on formation sands to illustrate the real advantage of the new methods over traditional measurement techniques. Furthermore, particle shape descriptors were used to explain the deviation between the results of different PSD measurement methods.


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2020

Authors: Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Kelly Berner (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ahmed Al-hadhrami (Occidental Petroleum Oman) | Ali Ghalambor (Oil Center Research International)


Standalone screens (SAS) have been widely employed as the main sand control solution in thermal projects in Western Canada. Most of the test protocols developed to evaluate screen designs were based on the scaled screen coupons. There have been discussions regarding the reliability of such tests on scaled coupons. This paper presents the results of the tests on full-scale wire-wrapped screen (WWS) and slotted liner coupons for typical McMurray Formation sands.

A large-scale sand control evaluation apparatus has been designed and built to accommodate all common SAS with 3 1/2″ in diameter and 12″ in height. The set-up provides the capability to have the radial measurement of the pressure across the sand pack and liner, for three-phase flow. We outline certain challenges in conducting full-scale testing such as establishing uniform radial flow and measuring the differential pressure. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow direction, flow rates and flow regimes.

We were able to establish uniform radial flow in both high and low permeability sand packs. However, the establishment of the radial flow in sand packs with very high permeability was extremely challenging. The pressure measurement in different points in radial direction around the liner indicated a uniform radial flow. Results of the tests on a representative PSD from McMurray Formation on the WWS and slotted liner coupons with commonly used specs in the industry have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to the previous large-scale tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and slotted liner. Accumulation of the fines close to screen causes significant pore plugging, when conservative aperture sizes were used for both WWS and slotted liner. On the other hand, using the coupon with larger aperture size than the industry practice, resulted in excessive sanding. The experiments under linear flow seems more conservative as their results show higher produced sand and lower retained permeability, in comparison to the full scaled testing under radial flow.

This work discusses the significance, procedure, challenges and early results of full-scale physical modeling of SAS in thermal operation. It also provides an insight into the fluid flow, fines migration, clogging and bridging in the vicinity of sand screens.


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2020

Authors: Mohammad Soroush (University of Alberta) | Seyed Abolhassan Hosseini (University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc) | Peyman Pourafshary (Nazarbayev University) | Mahdi Mahmoudi (RGL Reservoir Management Inc) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc)


Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan.

We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves.

Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding.

This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.


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2020

Authors: Morteza Roostaei (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Arian Velayati (University of Alberta) | Ahmad Alkouh (College of Technical Studies) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


Sieve analysis, sedimentation and laser diffraction have been the methods of choice in determining particle size distribution (PSD) for sand control design. However, these methods do not provide any information regarding the particle shape. In this study, we introduce the application of Dynamic Image Analysis (DIA) to characterize particle sizes and shape descriptors of sand bearing formations.

Dynamic Image Analysis, an advanced method of particle size and shape characterization, along with other PSD measurement methods, including sieving combined with sedimentation, and laser diffraction, was utilized to study size and shape variations of 372 unconsolidated formation sand samples from North America, Latin America, and the Middle East. Different methods were compared for the estimation of PSD and fines content, which is important for sand control design.

Through minimizing the sampling and measurement errors, the deviation between different PSD measurement techniques was attributed solely to the shape of the particles and the amount of fine fraction. For fines content measurement, the values obtained through Feret Min. parameter values (the minimum size of a particle along all directions) calculated by DIA and sieving measurement are comparable within a 5% confidence band. The deviation between the results of different methods becomes more significant by increasing fines content. Moreover, this deviation increases for less isodiametric grains. The fines and clay content show higher values when measured by any wet analysis. Laser diffraction also tends to overestimate the fines fraction and underestimate silt/sand fraction compared to other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed which chooses the equivalent sphere sizes of DIA with minimum deviation from sieving.

This study performs several measurements on formation sands to illustrate the real advantage of the new methods over traditional measurement techniques. Furthermore, particle shape descriptors were used to explain the deviation between the results of different PSD measurement methods.


Download paper

2020

Authors: Mohammad Soroush (University of Alberta) | Seyed Abolhassan Hosseini (University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc) | Peyman Pourafshary (Nazarbayev University) | Mahdi Mahmoudi (RGL Reservoir Management Inc) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc)


Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan.

We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves.

Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding.

This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
 

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2020

Authors: Edgar Alberto Mayorga Cespedes (Ecopetrol) | Morteza Roostaei (RGL Reservoir Management Inc.) | Alberto A. Uzcátegui (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Hossein Izadi (University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Brad Schroeder (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Dionis M. Gomez (Ecopetrol) | Edgar Mora (Ecopetrol) | Javier Alpire (Ecopetrol) | Joselvis Torres (Ecopetrol) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


Designing/Selecting the proper sand control mechanism for horizontal wells in unconsolidated heavy-oil reservoirs tend to be under-looked in some cases. Stand-alone completions pose some sand control challenges, which could jeopardize the oil production or even lead to critical problems. Massive sand production, screen/formation plugging, formation of velocity hot-spots and mechanical integrity failures are some of the well-known issues. This study attempts to optimize the sand control design for horizontal wells in a heavy-oil field in Colombia.

A careful selection of representative core data was made to study the variation of sand Particle Size Distribution (PSD) within the development area. Reservoir fluid properties were analyzed. Based on PSD variation and current design criteria in the industry, several seamed slotted-liner configurations were proposed as an alternative completion for testing. Later, a series of large-scale Sand Retention Tests (SRTs) were performed to assess the selected alternatives under typical field production conditions. Effects of aperture size and open to flow area (OFA) were investigated to evaluate flow and sand control performance.

This investigation started by a detailed study of the PSD, particle shape variation and composition of fines in the development area. The PSDs were then classified into four distinct minor and major sand facies, ranging from medium to very coarse sand with different fines content. Further investigations have shown that current design is only suitable for a limited number of PSDs, while the overall PSD classes indicate requirement of wider slot aperture sizes. The results of the SRTs indicated that the flow performance of the screen is mainly controlled by the slot aperture. Choosing the optimized aperture size avoids unacceptable sanding even for the multiphase flow scenarios with gas. Results also indicated that by increasing the aperture size and application of the seamed slots for the studied formation, plugging could be mitigated. Finally, a detailed Finite Element Analysis (FEA) was conducted to compare the mechanical integrity of the current slotted liner design and the optimized design obtained from the experimental testing.

A comprehensive sand control design workflow for cold primary heavy oil production in horizontal wells is presented in this work. The current study is one of the first that investigates and compares conventional straight slotted liners with seamed slotted liners at larger scale for a field. Moreover, this study helps to better understand the effect of design parameters of seamed slotted liners on sand control, flow performance and mechanical strength.

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2020

Authors: Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Seyed Abolhassan Hosseini (University of Alberta) | Mohammad Soroush (University of Alberta) | Kelly Berner (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ahmed Al-hadhrami (Occidental Petroleum Oman) | Ali Ghalambor (Oil Center Research International)


Most of the test protocols developed to evaluate sand-screen designs were based on scaled-screen test coupons. There have been discussions regarding the reliability of such tests on scaled test coupons. This paper presents the results of tests on wire-wrapped screen (WWS) and slotted liner (SL) test coupons for typical onshore Canada McMurray formation sand.

A unique sand control evaluation apparatus has been designed and built to accommodate all common stand-alone screens that are 3.5 in. in diameter and 12 in. in height. This setup provides the capability to have a radial measurement of pressure across the sandpack and screen for three-phase flow. Certain challenges during testing such as establishing uniform radial flow and measuring the differential pressure are outlined. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow directions, flow rates, and flow regimes.

It was possible to establish uniform radial flow in both high- and low-permeability sandpacks. However, the establishment of radial flow in sandpacks with very high permeability was challenging. The pressure measurement at different points in the radial direction around the screen indicated a uniform radial flow. Results of the tests on a representative particle size distribution (PSD) from the McMurray Formation on the WWS and SL test coupons with commonly used specifications in the industry (aperture sizes of 0.012, 0.014, and 0.016 in. for WWS and 0.012, 0.016, 0.018, and 0.020 in. for SL) have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to previous tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and SL. Accumulation of fines close to the screen causes significant pore plugging when conservative aperture sizes were used for both WWS and SL. In contrast, using the test coupon with a larger aperture size than the industry practice resulted in excessive sanding. The experiments under linear flow seem more conservative because their results show more produced sand and smaller retained permeability in comparison to the testing under radial flow.

This work discusses the significance, procedure, challenges, and early results of physical modeling of stand-alone screens in thermal operation. It also provides insight into the fluid flow, fines migration, clogging, and bridging in the vicinity of sand screens.
 

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2020

Authors: Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc.) | Arian Velayati (University of Alberta) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Mohammad Mohammadtabar (RGL Reservoir Management Inc., University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


Erosion of standalone screens in thermal wells can lead to significant damage and reduction in production. The dominant failure mechanism is the development of localized high-velocity hot spots in the screen due to steam breakthrough or flashing of the steam across the screen. This study provides methods to assess the erosion potential of screen material devices to determine the allowable production conditions which avoid erosion.

In this study the effects of impact angle, flow rate, sand concentration, particle size, and fluid viscosity on erosion are systematically investigated through a multivariable study. Experimental impingement testing is performed on screens in different orientations. Erosion is accessed by collecting weight loss data of the screen. Empirical erosion models are calibrated to provide predictions of functional relationships between erosion rate and varied parameters. Computational Fluid Dynamic (CFD) simulations are performed prior to the experimental work to visualize particle flow paths through the screen and determine local flow and impact velocities and wear patterns.

The performance of five existing erosion models is assessed through experimental testing of sand control screens. In order to translate short-term, high-velocity laboratory test results into field erosion predictions, an empirical erosion model is then developed and employed to provide well flow guidelines and minimize erosion potential. This suggests that the use of erosion prediction models in situations in which due to lack of time/data tuning is not possible, may still provide a reasonable estimate for the rate of material loss of the screen. The model is used to obtain threshold superficial velocity curves for several conditions.

The main concern associated with existing erosion models is that they do not consider sand production, nor do they account for many other factors that affect erosion process. An erosion model, coupled with CFD simulation, has been developed, that account for factors such as geometry, size, material, fluid properties and rate, sand size, shape, and density in downhole flow conditions.
 

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2020

Authors: Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Mark Anderson (Canadian Natural Resources Limited)


Primary Cold Heavy Oil Production with Sand (CHOPS) recovery factors are low (typically 8%) and most of the oil is left behind in the formation. Canadian Natural Resources Limited (Canadian Natural) is pursuing alternatives to primary recovery and secondary post CHOPS Enhanced Oil Recovery (EOR) to recover more of this stranded oil resource. Wire-wrapped screens were investigated, using a High-Pressure High Temperature Sand Retention Testing (HPHT-SRT) apparatus, for sand control and inflow performance in a CHOPS formation near Bonnyville, Alberta.

A new HPHT-SRT apparatus was designed/commissioned to better understand the role of oil viscosity on the capability of the standalone sand control screen. The facility allows to control the temperature of the fluid flowing across the sand pack and sand control coupon at different pressure drops. Each test is performed at constant pressure drops up to 300 psi. The temperatures up to 85 °C were tested. Coupons of wire-wrapped screen with three aperture sizes (0.008″, 0.010″, and 0.012″) were tested. Canadian Natural provided oil sand cores and crude oil from the target formation for this testing.

The results indicated a high dependency of the near screen flow performance on the temperature and oil viscosity. As the increase in temperature reduces the oil viscosity below 300 cP, the near screen pressure gradient falls 26% to 40% under constant pressure drop for different aperture sizes. As the screen aperture increases from 0.008″ to 0.012″, the flow rate increases up to 20% for the test stages at 85°C temperature and up to 162% for the test stages at 25°C, for the tested pressure drops. The results indicate that at higher viscosities, the aperture size is the dominant factor in screen flow performance where a slight increase in aperture increases the flow performance and reduces pressure drop. However, increasing the aperture size, up to 0.012″, led to an increase in the sanding over 0.20 lb per square feet of the screen (lb/sq.ft.), which exceeds the acceptable threshold of 0.12 to 0.15 lb/sq.ft. for typical SRTs. Based on the pressure drops and produced sand results, a 0.010″ aperture size was recommended for the target formation.

This paper outlines the results of the experiments with a HPHT-SRT, which is developed to better assess the function of sand control design for heavy oil assets. This phase of the work mainly focused on better understanding the role of the oil viscosity on sand control performance.

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2020

Authors: Morteza Roostaei (RGL Reservoir Management Inc.) | Edgar Alberto Mayorga Cespedes (Ecopetrol) | Alberto A. Uzcátegui (RGL Reservoir Management Inc.) | Mohammad Soroush (RGL Reservoir Management Inc. and University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc. and University of Alberta) | Hossein Izadi (University of Alberta) | Brad Schroeder (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Dionis M. Gomez (Ecopetrol) | Edgar Mora (Ecopetrol) | Javier Alpire (Ecopetrol) | Joselvis Torres (Ecopetrol) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


Designing and selecting the proper sand control mechanism for horizontal wells in unconsolidated heavy-oil reservoirs tend to be underlooked in some cases. Standalone completions pose some sand control challenges, which could jeopardize the oil production or even lead to critical problems. Massive sand production, screen/formation plugging, hot spots, and mechanical integrity failures are some of the well-known issues. This study attempts to optimize the slotted liner design for horizontal wells in a heavy-oil field in Colombia.

A careful selection of representative core data was made to study the variation of sand particle-size distribution (PSD) within the development area. Reservoir fluid properties were analyzed. Based on PSD variation and current design criteria in the industry, several seamed slotted-liner configurations were proposed as an alternative completion for testing. Later, a series of large-scale sand retention tests (SRTs) were performed to assess the selected alternatives under typical field production conditions. The effects of aperture size and open-to-flow area were investigated to evaluate flow and sand control performance.

This investigation started with a detailed study of the PSD, particle shape variation, and composition of fines in the development area. The PSD then classified into four distinct minor and major sand facies, ranging from medium to very coarse sand with different fines content. Further investigations have shown that current design is only suitable for a limited number of the PSDs, while the overall PSD classes indicate the requirement for wider slot aperture sizes. The results of the SRTs indicated that the flow performance of the screen is mainly controlled by the slot aperture. Choosing the optimized aperture size avoids unacceptable sanding even for the multiphase flow scenarios with gas. Results also indicated that by increasing the aperture size and application of the seamed slots for the studied formation, plugging could be mitigated.

A comprehensive sand control design workflow for cold primary heavy-oil production in horizontal wells is presented in this work. The current study is one of the first that investigates and compares conventional straight slotted liners with seamed slotted liners at a larger scale for this field. Moreover, this study helps to better understand the effect of design parameters of seamed slotted liners on sand control, flow performance, and plugging tendency.

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2020

Authors: Mohammad Soroush (RGL Reservoir Management Inc., University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mohammad Mohammadtabar (RGL Reservoir Management Inc., University of Alberta) | Seyed Abolhassan Hosseini (RGL Reservoir Management Inc., University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Mohtada Sadrzadeh (University of Alberta) | Ali Ghalambor (Oil Center Research International) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)


The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased hole gravel packing or frac-packing as the completion of the choice. Despite the reliability of these options, they are more expensive than standalone screen completion. Since several developments are not designed for cased hole gravel pack or frac-pack, purpose-driven sand control methods for cased and perforated wells are recommended.

This paper employs a combined physical lab testing and Computational Fluid Dynamics (CFD) for lab scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail.

A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the role of perforation density, the fill-up of annular gap between the casing and screen, perforation collapse and screen plugging on pressure drop. The experiments consisted of a series of step rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate in which the sand filled annular gap will fluidize and also sanding would be different for different fluid density. Both test results and CFD simulation scenarios comparatively allow to establish the relation between wellbore pressure drop with screen and perforation parameters and determine the optimized design.

The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completion. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy, rather than using gravel packing and frac-packing methods in cased and perforated completions.

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2019

Authors: Morteza Roostaei, Siavash Taghipoor, Alireza Nouri, Vahidoddin Fattahpour, Dave Chan


A smeared fracture type hydraulic fracture simulator is developed through numerical coupling between an in-house reservoir simulator and a geomechanical commercial software (FLAC2D). The new package falls within the category of partially decoupled model and is versatile, flexible and efficient. This approach can be used to couple any other advanced commercial fluid flow or geomechanical simulators for an accurate description of the initiation and propagation of hydraulic fractures.

The paper contains a discussion of the partial coupling technique to link fluid flow and geomechanical calculations in modeling fracture initiation and propagation. The models use a common gridblock for the fracture and reservoir and use the deformation calculations to update the porosity and permeability. The method captures the interactive effects of the fracture on reservoir fluid flow and formation geomechanics through stress dependent permeability and porosity.

The developed smeared fracture model can capture both tensile and shear fractures in the formation. Major features of this model include modeling poroelasticity and plasticity, matrix flow, shear and tensile fracturing with concomitant permeability enhancement, saturation-dependent permeability, stress-dependent stiffness and gradual degradation of oil sands due to dilatant shear deformation. The model has been applied to numerically simulate field size hydraulic fracturing in oil sands during cold-water injection to show the predictive capability of the simulator.
 

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2019

Authors: Mohammad Haftani (Unversity of Alberta) | Chenxi Wang (Unversity of Alberta) | Jesus David Montero Pallares (Unversity of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Alireza Nouri (Unversity of Alberta)

In Steam Assisted Gravity Drainage (SAGD) operations, condensed water dissolves the formation minerals and mixes with formation water, and its salinity changes over time. For the salinity levels below a critical salt concentration, brine reacts with the formation clays and affects their mobilization towards the production well. Migrated fine particles may plug the pore spaces around the well and reduce wellbore productivity. This paper aims to investigate the impact of water salinity on fines migration and permeability reduction.

A large-scale pre-packed Sand Retention Tests (SRT) facility was employed to simulate SAGD well conditions. Brine with different NaCl salt concentrations was injected into synthetic sand-pack samples that are representative of the McMurray Formation. Flow rates were varied during the test, and fines migration along the sand-pack was traced. Differential pressures along the sand pack were recorded to calculate the permeability changes during the test. Samples of produced water were collected immediately below the coupon to measure the fines concentration. Testing parameters such as pH, clay mineralogy, temperature, and sand control specifications were kept constant in all tests.

Fines concentration in the produced water during the test and retained permeability were considered as the indicators of the fines migration inside the sand-pack. Results of step-rate testing display a jump in fines concentration in produced water right after each flow rate increase. Besides, fines concentration results show that fines migration was insignificant when using brine with high salt concentrations. Fines migration was stronger for a relatively narrow salinity range with low NaCl concentrations, resulting in the highest pore plugging. The findings in this research are consistent with past studies which relate clay dispersion to the zeta potential of clay materials: the higher the zeta potential, the stronger the fines dispersion and migration.

Based on this study, it is recommended that the operating companies monitor the chemical properties of the produced water. Field operators could preserve the reservoir productivity by manipulating the formation salinities to lower the dispersion and detachment of fines and their migration towards the production well.

 

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2019

Authors: A. Velayati (University of Alberta) | M. Roostaei (RGL Reservoir Management Inc) | A. Sharbatian (RGL Reservoir Management Inc) | V. Fattahpour (RGL Reservoir Management Inc) | M. Mahmoudi (RGL Reservoir Management Inc) | C. F. Lange (University of Alberta) | A. Nouri (University of Alberta)

Well completion is the process of borehole preparation for the production. Cased and perforated slotted liner completion is used extensively as the completion configuration in the wells drilled into conventional sand formation reservoirs. Such completions may exhibit lower productivity ratios compared to the open-hole condition. The reasons include perforations collapse, flow convergence in the vicinity of the slots and perforations, and the formation damage caused by perforating. These effects have compounding effects as the formation damage magnifies the flow convergence effect and the flow convergence magnifies the skin buildup by the fines migration. In this study, a Computational Fluid Dynamics (CFD) numerical finite volume model was constructed for a vertical cased and perforated completion in a sand reservoir. Results include the skin values that were compared for the different slot and perforation densities. Stability of the perforation tunnels was considered as a variable in this research, and the results were summarized and analyzed in terms of the skin formed as a result of flow convergence. It was found that sanding in perforation tunnels and the resulting change in the permeability of the collapsed tunnel magnifies flow convergence skin significantly, especially in the lower shot densities and this added pressure drop can be very troubling. Results show in lower perforation densities higher pressure drawdowns may trigger sand production due to the tensile failure. Additionally, a parametric study was carried out on the sanding possibilities.

 

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2019

Authors: J. D. Montero Pallares (University of Alberta) | C. Wang (University of Alberta) | A. Nouri (University of Alberta) | M. Haftani (University of Alberta) | M. Mahmoudi (RGL Reservoir Management) | V. Fattahpour (RGL Reservoir Management)

A three-phase flow large pre-packed Sand Retention Test (SRT) assembly was employed with different screen specifications for typical sand prints within McMurray Formation in Western Canada. Cumulative sand production and retained permeability are utilized as the sand control and plugging performance indicators. Measurements indicate that sand production is highly dependent on the flow dynamics and near-wellbore velocities. Most aperture sizes smaller than two and half times of the mean grain size show a good performance during liquid stages, but wider apertures dramatically failed during steam-breakthrough emulation (three-phase flow). Wire-wrapped screens exhibited an excellent flow performance due to the high open-to-Flow Area (OFA). Existing criteria provide reasonable aperture sizes, especially for finer sands and challenging conditions such as steaminflux. However, the criteria underestimate the slot aperture for coarser sands and conventional liquid production operations. This conservative approach may result in lower productivity performances and diminish the benefits of the high OFA.

 

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2019

Authors: M. Roostaei (RGL Reservoir Management Inc.) | A. Sharbatian (RGL Reservoir Management Inc.) | V. Fattahpour (RGL Reservoir Management Inc.) | M. Mahmoudi (RGL Reservoir Management Inc.) | A. Velayati (University of Alberta, Edmonton) | A. Ghalambor (Oil Center Research International) | A. Nouri (University of Alberta, Edmonton)

This paper presents an analytical model to calculate the hydraulic fracture initiation pressure from an arbitrarily oriented wellbore in an elastic medium with and without perforations and investigates the competition between axial and transverse fractures. The model predicts the location of fractures and their initiation pressures, in relation to the in-situ stress condition and wellbore azimuth and inclination. Not only has the model been applied to different states of in-situ stress and wellbore orientations, but also the results have been presented in terms of non-dimensional parameters to improve the applicability of the study.

The presence of both transverse and axial hydraulic fractures can cause significant near-wellbore tortuosity. Besides, the stress distribution around the perforation tunnel has a substantial impact on the fracture initiation pressure and thus the fracture geometry near the wellbore. The introduced analytical model was verified against existing models. The model has been successfully applied to different conditions of in-situ stress and wellbore orientations, which were not addressed in previous studies. The results can be used to obtain the optimum well and perforation design in deviated wellbores by providing the minimum fracture initiation pressure and the perforation orientation that minimizes the near-wellbore fracture tortuosity.

 

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2019

Authors: Seyed Abolhassan Hosseini (University of Alberta, RGL Reservoir Management Inc.) | Morteza Roostaei (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Ahmad Alkouh (College of Technological Studies) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.)

Production from weakly and unconsolidated sand formations relies on the efficiency of the employed sand control method. Performance of current sand control devices is based on surface size exclusion and depth filtration depending on their geometry and application. In this study, we investigate the possibility of using the advantage of both mechanisms in a single device.

The standard cut point test was used to determine the micron rating of different meshes in order to categorize them in different classes based on the average pore size. Different mesh weaves, namely Dutch twill, reversed Dutch twill and square mesh screens with different micron rating were investigated in terms of filtration performance. In the next step, a dead-end filtration set-up was designed and commissioned to evaluate the flow performance and sand control capabilities of mesh screens. Additionally, a new, customized sand control device was designed and included in the testing matrix to compare its performance with the common mesh screens in the market.

Dead-end filtration results indicated that by choosing the proper combination of morphology, both optimized open to flow area (OFA) and sand control could be achieved. The custom designed hybrid screen performed better compared to other investigated mesh screens with similar micron rating, in terms of both flow and filtration performance. Therefore, the customization was found to be the key parameter to achieve the optimized design. This further emphasizes that by employing the hybrid benefits of surface size exclusion and depth filtration, one can reach the optimized sand control and flow performance. Regarding the weave of different mesh screens, the results did not show any trends that could lead to a conclusion of better performance of a certain weave. Further investigations are required under different testing condition to achieve a conclusive comparison between different mesh types.

This paper investigates the possibility of customized sand control design, which uses the hybrid benefits of surface size exclusion and depth filtration to reach the optimized sand control and flow performance.

 

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2018

Authors: Morteza Roostaei (RGL Reservoir Management) | Omar Kotb (University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management) | Vahidoddin Fattahpour (RGL Reservoir Management) | Chenxi Wang (University of Alberta) | Alireza Nouri (University of Alberta) | Brent Fermaniuk (RGL Reservoir Management)

Open hole gravel pack (OHGP) has been broadly used for completion of steam-drive production wells. However, some failures have been observed with the gravel pack in such complex completions. This paper aims to better understand the OHGP performance in steam-drive production wells and examine the performance of rolled-top and straight-cut slotted liners using a large-scale Sand Retention Testing (SRT).

A large-scale SRT facility was developed to investigate the performance of the gravel pack in two-phase flow regime. The testing set-up allows for co-injection of oil and brine at controlled flow rate and water cut level to emulate different scenarios for two-phase flow across the gravel pack and sand screen/liner. Testing measurements included produced sand, absolute pressures, and differential pressure drops across the slotted liner, gravel pack, gravel-sand pack interface and sand pack. The test procedure and test matrix were designed to enable an accurate assessment of the gravel pack and slotted liner performance for different fluid flow scenarios. Rolled-top and straight-cut slotted liner coupons were used for this study.

Test results showed negligible sand production for both rolled-top and straight-cut slotted liners, however the produced sand was slightly higher for the rolled-top profile. The pressure drop across the rolled-top liners were smaller than the straight-cut liners based on the analytical analysis presented in this study. The results have also shown that a key factor in gravel packing performance is the ratio of the gravel pack size to the formation sand (sand pack) size. Larger gravels allow an easier production of the fines, while smaller gravels may trap the fines and be plugged over time.

This work provides a robust testing facility to address the gravel pack performance in steam-drive producer wells. The results help the engineers with gravel pack and sand control design and an evaluation for the entire wellbore life.

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2018

Authors: M. Mahmoudi (RGL Reservoir Management Inc.) | V. Fattahpour (RGL Reservoir Management Inc.) | M. Roostaei (RGL Reservoir Management Inc.) | O. Kotb (University of Alberta) | C. Wang (University of Alberta) | A. Nouri (University of Alberta) | C. Sutton (RGL Reservoir Management Inc.) | B. Fermaniuk (RGL Reservoir Management Inc.)

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.

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2018

Authors: J. D. Montero (University of Alberta) | S. Chissonde (University of Alberta) | O. Kotb (University of Alberta) | C. Wang (University of Alberta) | M. Roostaei (University of Alberta) | A. Nouri (University of Alberta) | M. Mahmoudi (RGL Reservoir Management Inc.) | V. Fattahpour (RGL Reservoir Management Inc.)

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.

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2018

Authors: V. Fattahpour (RGL Reservoir Management Inc.) | M. Mahmoudi (RGL Reservoir Management Inc.) | M. Roostaei (RGL Reservoir Management Inc.) | C. Wang (University of Alberta) | O. Kotb (University of Alberta) | A. Nouri (University of Alberta) | C. Sutton (RGL Reservoir Management Inc.) | B. Fermaniuk (RGL Reservoir Management Inc.)

Injector wells in thermal field developments in Western Canada are usually completed by slotted liners. The purpose of liner installation is preventing sand production after a shut-in, keeping a stable wellbore, and providing an appropriate steam distribution. The objective of this paper is to quantify the role of slot width and slot density on the sanding performance of the liner in cycles of injection and shut-in in a SAGD injection well, through a series of laboratory sand control tests.

A large-scale sand retention testing facility was developed and employed to conduct a series of tests on slotted liner coupons with different slot widths and densities. These tests were tailored to simulate steam injection and backflow during the shut-in. Three representative particle size distributions for the McMurray Formation were used in this study ranging from coarse to fine sand. The experimental set-up allows to measure the amount of produced sand.

Since the produced sand in steam injection wells is not usually cleaned out, the acceptable threshold for sand production in the injector should be more conservative than the same for producer wells. Testing results indicate that the sand control performance of the liner is governed by the slot width and density, and formation particle size distribution. Results indicate a negligible amount of produced sand with gas backflow for a properly designed liner even at very high gas velocities.

Historically, there has been little attention to the sand control design for injector wells. This work highlights the significance of slot density and slot width in the sand control performance for steam injection wells. The paper provides the basis for the proper design of an effective sand control in SAGD injectors.

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2018

Authors: Roostaei, Mohammad & Nouri, Alireza & Fattahpour, V. & Mahmoudi, Mahdi & Izadi, M. & Ghalambor, Ali & Fermaniuk, B.

Standalone screen (SAS) design conventionally relies on particle size distribution (PSD) of the reservoir sands. The sand control systems generally use D-values, which are certain points on the PSD curve. The D-values are usually determined by a linear interpretation between adjacent measured points on the PSD curve. However, the linear interpretation could result in a significant error in the D-value estimation, particularly when measured PSD points are limited and the uniformity coefficient is high. Using the mathematical representation of the PSD is an efficient method to mitigate these errors. The aim of this paper is to assess the performance of different mathematical models to find the most suitable equation that can describe a given PSD.

The study collected a large databank of PSDs from published SPE papers and historical drilling reports. These data indicate significant variations in the PSD for different reservoirs and geographical areas. The literature review identified more than 30 mathematical equations that have been developed and used to represent the PSD curves. Different statistical comparators, namely, adjusted R-squared, Akaike's Information Criterion (AIC), Geometric Mean Error Ratio, and Adjusted Root Mean Square Error were used to evaluate the match between the measured PSD data with the calculated PSD from the formulae. The curve fit performance of the equations for the overall data set as well as PSD measurement techniques were studied. A particular attention was paid towards investigating the effect of fines content on the match quality for the calculated versus measured curves.

It was found that certain equations are better suited for the PSD database used in this investigation. In particular, Modified Logestic Growth, Fredlund, Sigmoid and Weibull models show the best performance for a larger number of cases (highest adjusted R-squared, lowest Sum of Squared of Errors predictions (SSE), and very low AIC). Some of the models show superior performance for limited number of PSDs. Additionally, the performance of PSD parameterized models is affected by soil texture: For higher fines content, the performance of equations tends to deteriorate. Moreover, it appears the PSD measurement techenique can influence the performance of the equations. Since the majority of the PSD resources used here did not mention their method of measurement, the effect of measurement technique could only be tested for a limited data, which indicates the measurement technique may impact the match quality.

Fitting of parameterized models to measured PSD curves, although well known in sedimentology and soil sciences, is a relatively unexplored area in petroleum applications. Mathematical representation of the PSD curve improves the accuracy of D-values determination, hence, the sand control design. This mathematical representation could result in a more scientific classification of the PSDs for sand control design and sand control testing purposes.

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2018

Authors: M. Mahmoudi (RGL Reservoir Management) | V. Fattahpour (RGL Reservoir Management) | C. Wang (University of Alberta) | O. Kotb (University of Alberta) | M. Roostaei (University of Alberta) | A. Nouri (University of Alberta) | B. Fermaniuk (RGL Reservoir Management) | A. Sauve (RGL Reservoir Management) | C. Sutton (RGL Reservoir Management)

Sand production is not usually considered a major concern during the injection phase in injection wells. However, well shut-in for service requirements or sudden pump failure, hence the backflow towards the wellbore and potential generation of water hammer pressure pulsing, can lead to massive sand production under favorable conditions. With the aim of sanding prevention, this paper examines the design criteria for standalone screens (SAS) in injection wells using a novel sand control testing facility.

This paper presents a new large-scale sand retention testing (SRT) facility to simulate the effect of pressure pulsation and backflow in injection wells on the sand control performance of SAS. The SRT facility can be used in the selection of the best sand control method for injector wells. It can be also used to provide further understanding on the impact of formation damage on well injectivity decline, as well as study the effect of water hammer pressure pulsation on sand production in injection wells.

Test results show a rapid fall off in the pressure and drastically high backflow rates due to the sudden shut-in. Higher pressure drops are observed to result in a greater backflow volume and a longer backflow period. Results also show that the slot width has a drastic influence on the sanding performance of the screen. Testing observations, for the studied PSD, indicate that the injection well requires narrower slots 1.4 D10 to meet the sand production requirements due to a high fluidization potential in the near-screen zone. Higher flow velocities during the backflow period and the tossing effect caused by the pressure waves increase the sanding potential. The produced sand during the backflow period, is observed to mainly relate to the ratio of the slot width to the mean formation grain size. It is observed that higher effective stresses around the screen work towards stabilizing the sand bridges and reducing the amount of produced sand.

This paper presents a new experimental test facility for the sand control type selection and evaluation for injection wells with the aim of limiting the amount of produced sand and sustaining the wellbore injectivity. The proposed testing facility allows the performance comparison of different sand control devices and designs.

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2018

Authors: Chenxi Wang (University of Alberta) | Yu Pang (University of Alberta) | Jesus Montero (University of Alberta) | Mohammad Haftani (University of Alberta) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Alireza Nouri (University of Alberta)

Thermal stimulation techniques are widely used to exploit Western Canadian heavy oil assets. These techniques rely on injection of steam into the formation, inducing complex geomechanical stresses in the reservoir and surrounding strata during the life cycle of the project. In SAGD wells, the collapsed oil sand around the liner undergoes a stress buildup which causes gradual sand compaction. The stress buildup is influenced by several factors such as the in-situ stresses, reservoir poroelastic and thermal expansion, and reservoir shear dilation. However, the impact of stress level and anisotropy around the liner is not properly accounted for in previous research on slotted liner design. This paper investigates the effect of anisotropic stress buildup around slotted liners on their sanding and plugging performance under multiphase flow conditions.

A Scaled Completion Testing (SCT) facility was utilized to emulate multi-axial stress and multiphase flow conditions near the sand control liner. Brine, oil, and gas were used as flowing fluids. Sand-pack samples were prepared using commercial sands by matching the particle size, shape and, composition of the McMurray Formation oil sands. A constant lateral stress and several axial stresses were applied to simulate the stress conditions around the liner. The three-phase flow condition was used to evaluate the role of the steam breakthrough on the liner performance.

Experimental results indicate the critical role of stress conditions around the liner on its sanding and plugging responses. Results show gradual sand-pack compaction with the gradual increase of the axial stress. Higher axial stresses result in a smaller amount of produced sand, which can be attributed to the stronger inter-particle frictional resistance, hence, stronger and more stable sand bridges behind the slots. The higher compaction results in a lower porosity and permeability, hence, altering the plugging and sanding response of the liner. Also, higher retained permeabilities are found for stronger anisotropic stress conditions. Besides, it is found that the three-phase flow condition could cause a stronger fines migration and production, compared to single-phase flow.

The results of this study indicate that the stress and multiphase flow effects are crucial factors in the evaluation of slotted liner performance. The findings from the innovative experimental studies provide insights into the practicability of evaluating slotted liner performance with the consideration of sophisticated field conditions and optimizing the selection of the slotted liner aperture for the entire well lifespan.

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2018

Authors: Yujia Guo, Morteza Roostaei, Alireza Nouri, Vahidoddin Fattahpour, Mahdi Mahmoudi, Heeseok Jung

Steam Assisted Gravity Drainage (SAGD) is the primary thermal recovery technology currently employed to extract heavy oil and high-viscosity bitumen from Alberta oil sands. In the near-wellbore region, the initial stresses are nearly zero, and as the SAGD chamber grows, the stresses tend to build up due to the thermal expansion of the formation. Also, melting of the bitumen and subsequent loss of the bonding between the grains leads to the collapse of the gap between the formation and sand control liner over time. The result will be effective stress buildup and gradual compaction of the oil sands around the liner.

Slotted liners have been extensively used as a sand control device in SAGD wells. Slotted liners must allow free flow through the slots with minimal plugging and acceptable amounts of sand production.

In our study, large-scale unconsolidated sand was packed over a multi-slot coupon of the slotted liner. The sand-pack was subjected to several stress conditions corresponding to the evolving stress conditions during the life cycle of a SAGD producer well. The testing program employed several multi-slot coupons to examine the flow performance under typical encountered stresses in SAGD wells. Cumulative produced sand was measured at the end of testing as an indicator of the sand control performance. The permeability evolution of the sand in the near-coupon zone was calculated by measurements of pressure differentials and considered as a measure of screen flow performance. Fines/clay concentration along the sand-pack was also quantified after the test to investigate the fines migration, a phenomenon which is considered to be the main reason for reduced wellbore productivity.

Experimental results show that the liner performance is significantly affected by the normal stress buildup on the liner. Experimental observations indicate sand-pack compaction due to the increase of effective stress around the liner leads to a lower porosity and permeability. The situation near the liner is further complicated by the fines accumulation that results in pore plugging and further permeability reduction. When it comes to sanding, however, higher stresses help stabilize the sand bridges behind the slots, leading to less sand production.

As for the design criteria, the lower and upper bounds of the slot size are governed by plugging and sand production, respectively. Considering the stress effect on plugging and sanding, testing data indicate that both the lower and upper bounds should be revised to larger slot aperture sizes.

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2018

Authors: Anas Sidahmed (University of Alberta) | Alireza Nouri (University of Alberta) | Mohammad Kyanpour (RGL Reservoir Management Inc.) | Siavash Nejadi (University of Alberta) | Brent Fermaniuk (RGL Reservoir Management Inc.)

Canada has enormous oil reserves which ranks third worldwide with proven oil reserves of 171 billion barrels. Alberta alone contributes with 165.4 billion barrels found in oil sands. However, the oil in oil sands is extremely viscous, and only 10% is recoverable through open-pit mining. In-situ thermal recovery methods such as Steam-Assisted Gravity Drainage (SAGD) have been developed and adopted as an efficient means to unlock the oil sands reserves.

Different reservoir geological settings and long horizontal wells impose limitations and operational challenges on the implementation of SAGD technology. Wellbore trajectory excursions or undulations- unintentionally generated trajectory deviations due to suboptimal drilling operations- are some of the complications that lead to non-uniform steam chamber conformance, high cumulative Steam-Oil Ratio (cSOR) and low bitumen recovery.

Conventional dual-string completion scheme (a short tubing landed at the heel, and a long tubing landed at the toe) has been widely adopted in most of the SAGD operations. Such configurations allow steam injection at two points: the toe and the heel sections of the horizontal well. However, these completions have demonstrated poor efficiency when reservoir/well complications exist. Tubing-deployed Flow Control Devices (FCD's) have been introduced to offer high flexibility in delivering specific amounts of steam to designated areas (such as low permeability zones) and ensure uniform development of steam chamber in the reservoir. The work in this thesis presents the results of a numerical effort for optimizing the design of Outflow Control Devices (OCD's) in SAGD wells for different scenarios of well pair trajectory excursions.

A coupled wellbore-reservoir SAGD simulation model was constructed to optimize the placement and number of ports in every single OCD. Three different cases were generated from the constructed basic SAGD model with each case having a specific well pair trajectory which causes variable lateral distances between the well pair.

Results of the optimized OCD's cases demonstrate a higher SAGD efficiency compared to their corresponding conventional dual-string cases. Those enhancements resulted in a higher steam chamber conformance, a higher cumulative oil production, and an improved Net Present Value (NPV).

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2018

Authors: M. Roostaei (University of Alberta) | Y. Guo (University of Alberta) | A. Velayati (University of Alberta) | A. Nouri (University of Alberta) | V. Fattahpour (RGL Reservoir Management) | M. Mahmoudi (RGL Reservoir Management)

Unconsolidated sand was packed on a slotted-liner coupon in large-scale sand retention tests (SRT) and was subjected to several stress conditions, corresponding to the evolving stress conditions during the life cycle of a SAGD producer. Cumulative produced sand at the end of testing was measured as the indicator for sand control performance. Retained permeability was calculated by measuring pressure drops near the liner and was considered as the quantification of the flow performance of the liner. Experimental results indicate the liner performance is significantly affected by the stress induced compaction of the oil sand. The stress results in the sand compaction, leading to a denser sand, hence, a lower porosity and permeability. The lower porosity results in a higher pore-scale flow velocity, which can trigger more fines mobilization, hence, a higher skin buildup. With respect to sanding, the higher stress can stabilize the sand bridges: Increased normal forces between near-slot sand particles result in a higher inter-particle friction, hence, more stable sand bridges and less produced sand. The lower and upper bounds of slot window are governed by plugging and sand production, respectively. Experimental results indicate an upward shift in both the lower and upper bounds at elevated stress conditions.

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2018

Authors: Arian Velayati (University of Alberta) | Morteza Roostaei (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Alireza Nouri (University of Alberta) | Ahmad Alkouh (College of Technical Studies) | Brent Fermaniuk (RGL Reservoir Management Inc.) | Mohammad Kyanpour (RGL Reservoir Management Inc.)

Several parameters affect the skin factor of the cased and perforated (C&P) wells completed with slotted liners. Existing skin factor models for slotted liners account for such factors as the flow convergence, pressure drop and partial production but neglect phenomena such as partial plugging of the screen or near-wellbore permeability alterations during the production. This paper discusses these factors and incorporates them into a skin model using a finite volume simulation.

The finite volume analysis evaluates the skin factor as a result of pressure drop in the gap between the casing wall and the slotted liner. This skin model accounts for: 1) the perforation density and phasing, 2) slotted liner specifications, and 3) different amount of sand accumulation in the annular space between the casing and the sand screen. A semi-analytical pressure drop model is also linked to the numerical model to incorporate the skin factor due to flow convergence behind the perforations.

The results of finite volume analysis reveal that a low perforation density would behave close to the open-hole completion for sand-free casing-liner annular space. Conversely, pressure drops were found to be significant for a partially or totally filled space. Additionally, it was found that the optimum completion design occurs if the slotted liner joints are in line with the casing joints. Besides, a partially perforated casing or a partially open sand screen increases the distance fluids have to travel in the annular space and intensifies the skin factor.

This paper provides skin models derived for vertical and perforated wells completed with slotted liner sand screens using the finite volume simulations. Each part of the model has been verified against existing numerical models in the literature. The model improves the understanding of flow performance of the sand screens and skin factor, which in turn leads to a better design of sand control completions.

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2018

Authors: Mahdi Mahmoudi (RGL Reservoir Management) | Vahidoddin Fattahpour (RGL Reservoir Management) | Arian Velayati (University of Alberta) | Morteza Roostaei (RGL Reservoir Management) | Mohammad Kyanpour (RGL Reservoir Management) | Ahmad Alkouh (College of Technological Studies) | Colby Sutton (RGL Reservoir Management) | Brent Fermaniuk (RGL Reservoir Management) | Alireza Nouri (University of Alberta)

Sand control and sand management require a rigorous assessment of several contributing factors including the sand facies variation, fluid composition, near-wellbore velocities, interaction of the sand control with other completion tools and operational practices. A multivariate approach or risk analysis is required to consider the relative role of each parameter in the overall design for reliable and robust sand control. This paper introduces a qualitative risk factor model for this purpose.

In this research, a series of Sand Retention Tests (SRT) was conducted, and results were used to formulate a set of design criteria for slotted liners. The proposed criteria specify both the slot width and density for different operational conditions and different classes of Particle Size Distribution (PSD) for the McMurray oil sands. The goal is to provide a qualitative rationale for choosing the best liner design that keeps the produced sand and skin within an acceptable level. The test is performed at several flow rates to account for different operational conditions for Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) wells. A Traffic Light System (TLS) is adopted for presenting the design criteria in which the red and green colors are used to indicate, respectively, unacceptable and acceptable design concerning sanding and plugging. Yellow color in the TLS is also used to indicate marginal design.

Testing results indicate the liner performance is affected by the near-wellbore flow velocities, geochemical composition of the produced water, PSD of the formation sand and fines content, and composition of formation clays. For low near-wellbore velocities and typical produced water composition, conservatively designed narrow slots show a similar performance compared to somewhat wider slots. However, high fluid flow velocities or unfavorable water composition results in excessive plugging of the pore space near the screen leading to significant pressure drops for narrow slots. The new design criteria suggest at low flow rates, slot widths up to three and half times of the mean grain size will result in minimal sand production. At elevated flow rates, however, this range shrinks to somewhere between one and a half to three times the mean grain size.

This paper presents novel design criteria for slotted liners using the results of multi-slot coupons in SRT testing, which is deemed to be more realistic compared to the single-slot coupon experiments in the previous tests. The new design criteria consider not only certain points on the PSD curve (e.g., D50 or D70) but also the shape of the PSD curve, water cut, and gas oil ratio and other parameters.

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2018

Authors: Jesus David Montero Pallares (University of Alberta) | Chenxi Wang (University of Alberta) | Mohammad Haftani (University of Alberta) | Yu Pang (University of Alberta) | Mahdi Mahmoudi (RGL Reservoir Management Inc.) | Vahidoddin Fattahpour (RGL Reservoir Management Inc.) | Alireza Nouri (University of Alberta)

This study presents an evaluation of Wire-Wrapped Screens (WWS) performance for SAGD production wells based on Pre-packed Sand Retention Testing (SRT). The impacts of features such as flow rates, water cut, steam-breakthrough events and fluid properties on flow performance and sand production are analyzed. The aim is to obtain a better understanding of WWS performance under several SAGD operational conditions for typical sand classes in the McMurray Formation in Western Canada.

The study employs a large pre-packed SRT to assess the performance of WWS with different aperture sizes and standard wire geometries. The testing plan includes sand samples with two representative particle size distributions (PSD's) and fines contents. Testing procedures were designed to capture typical field flow rates, water cut, and steam-breakthrough scenarios. The amount of sand production and pressure drop across the zone of the screen and adjacent sand were measured and used to assess the screen performance. Furthermore, fines production was measured to evaluate plugging tendencies and flow impairment during production.

The experimental results and data analysis show that aperture selection of WWS is dominated by their sand retention ability rather than the flow performance. The relatively high open flow area (OFA) makes WWS less prone to plugging. There is an increase in flow impairment after finalizing the injection scheme (oil+water+gas); however, it is controlled over the acceptable margins even with a narrow aperture. Further, a comparison of initial and final turbidity measurements showed that fines mobilization and production during single-phase brine flow was higher than in two-phase brine-oil flow at the same liquid flow rate. Excessive produced sand was observed for wider slots during the multi-phase (brine, oil, and gas) flow when gas was present, highlighting the impact of the breakthrough of wet steam on sand control performance. Flow impairment and pressure drop evolution were strongly related to the mobilization and accumulation of fines particles in the area close to the screen coupon; it is critical to allow the discharge of fines to maintain a high-retained permeability. Results also signify the importance of adopting adequate flow rates and production scenarios in the testing since variable water cuts and GORs showed to impact both sanding and flow performances.

This research incorporates both single-phase and multiphase flow testing to improve design criteria for wire-wrapped screens and provide an insight into their performance in thermal recovery projects. An improved post-mortem analysis includes fines production measurements to correlate these to the retained permeability caused by the pore plugging, which has hardly been evaluated in previous studies.

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2018

Authors: Mahdi Mahmoudi (RGL Reservoir Management) | Morteza Roostaei (RGL Reservoir Management) | Vahidoddin Fattahpour (RGL Reservoir Management) | Alberto Uzcatequi (RGL Reservoir Management) | Jeff Cyre (RGL Reservoir Management) | Colby Sutton (RGL Reservoir Management) | Brent Fermaniuk (RGL Reservoir Management)

Although several workflows have been developed over the years for the design of the optimal sand control solutions in thermal applications, numerous sand control failures still occur every year. This paper aims at assessing the failure mechanism of different sand control techniques and the factors contributing to the failure by analyzing different failed sand control screen samples recovered from thermal and non-thermal wells.

Several failed standalone screens have been studied, which were collected from various fields and operational conditions. The screens were first inspected visually, and then certain sections of screens/pipes were selected for more detailed study on the failure mechanism. The liners/screens were cut into sections to be studied through SEM-EDX, reflective light microscopy, X-ray micro CT scan and petrographic thin sections to better understand the localized plugging mechanism. Through the studies of several polished sections, a statistical variation of the plugging zone was found. Moreover, we further focused on the critical zones such as the inlet and outlet of the aperture and the zone adjacent to the formation to better investigate the plugging mechanism.

The study on wire wrap screen samples revealed significant plugging of the annular space between the base pipe and the screen. Extensive clay/fines buildup in the annular space led to full to partial clogging in some sections. The base pipe corrosion study reveals that the corrosion mechanism is highly flow dependent since the perforation on the base pipe was enlarged to an oval shape from the original circular shape with its larger axis pointing toward the flow direction. The size of the plugged zone was significantly higher in the outer diameter section where a mixture of the clay and corrosion byproducts plugged the near screen pore space and the screen aperture. Examined premium mesh screen samples showed that the plugging mechanism is highly sensitive to the mesh size and assembly process. The highest pore impairments were associated with mesh screens in which the mesh was directly wrapped around the base pipe causing a reduced annular gap for the flow toward the perforations. The investigation of slotted liner samples showed widest plugging zone in the slot entrance and the lowest on the slot wall. A distinct interplay of the clay and corrosion byproduct led to the adsorption of clay, forming a compacted layer over the slot wall.

This paper reviews the plugging mechanism of the standalone sand control screen obtained from the field to provide first-hand evidence of the plugging mechanism and provides explanations for some of the poor field performances. The results could help engineers to better understand the micro-scale mechanisms leading to sand control plugging.

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2018

Authors: Vahidoddin Fattahpour (RGL Reservoir Management) | Mahdi Mahmoudi (RGL Reservoir Management) | Morteza Roostaei (RGL Reservoir Management) | Patrick Nolan (Canadian Natural Resources Limited) | Colby Sutton (RGL Reservoir Management) | Brent Fermaniuk (RGL Reservoir Management)

With the aging of the SAGD projects and growing number of wells with hot-spot and sand production problems, there is a growing interest in the remedial completion with Inflow Control Device (ICD) and tubing deployed scab liner. The current study aims at better understanding the annular flow, sand transport in the annular space and the expected pressure drops and the produced sand for tubing deployed scab liner sand control solution using a large-scale experimental well simulator.

A large-scale wellbore simulator was developed to study the performance of the tubing deployed scab liner screen as remedial sand control, where the sand entry point, the concentration and PSD of the sand in addition to the flow rate and the ratio of different phases could be controlled precisely. Two-phase flow of oil and brine along with sand could be injected through different ports along the clear pipe, emulating the slurry flow entering into the wellbore. Clear pipe allows visualization of the sand transport and sand accumulation above the tubing deployed scab liner during the fluid injection. An experimental study of the performance of Wire Wrap Screen (WWS) with different aperture sizes is presented in this paper.

Results indicated the requirement of a different approach for designing the correct aperture size for remedial scab liners since using the current design sand control criteria leads to large amount of solid production. It seems that the design of aperture size for scab liners should be more toward the lower bound in comparison with the common screen designs in thermal applications. The sand entry point distance from the tubing deployed scab liner screen position was found to be the critical parameter in the sanding and flow performance of the remedial sand control. Fluid flow in the annulus causes the segregation of sand grains; finer grains are carried with fluid, while coarser grains settle closer to the injection ports. The slurry flow regime in the annulus results in continuous sand production until a stable bridge and later a stable sand bed is formed on top of the tubing deployed scab liner screen. Moreover, results showed that the main pressure drop happens across the nozzles on the tubing, while the pressure drop across the accumulated sand pack in the annulus and coupon was less significant.

This paper introduces an experimental tool for evaluating the tubing deployed scab liner performance as remedial sand control in thermal applications. The developed experimental testing and facility could help to better design and evaluate the remedial tubing deployed scab liner sand control solutions.

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2017

Authors: M. Mahmoudi (RGL Reservoir Management Inc.) | S. Nejadi (University of Alberta) | M. Roostaei (University of Alberta) | J. Olsen (University of Alberta) | V. Fattahpour (RGL Reservoir Management Inc.) | C. F. Lange (University of Alberta) | D. Zhu (RGL Reservoir Management Inc.) | B. Fermaniuk (RGL Reservoir Management Inc.) | A. Nouri (University of Alberta)

The term skin is used to describe pressure drop caused by a flow restriction near the wellbore. The skin factor of wells completed using slotted liners can be explained by a number of phenomena including: the flow across the slots, flow convergence towards slots, near wellbore permeability, and occlusion of liner open area due to corrosion and scale deposition. This paper introduces an analytical skin model for the slotted liner, which incorporates these phenomena, and can be used to optimize the slotted liner design. The introduced analytical model was verified by physical and Computational Fluid Dynamics (CFD) models.

The proposed analytical skin factor model for slotted liners is based on slot width, slot density, the spatial distribution of slots, and near-liner permeability. The model also incorporates partial plugging of slots. The model is validated using experimental Sand Retention Testing (SRT) data. A series of SRT experiments were conducted at different flow rates for two Particle Size Distributions (PSD) from the McMurray Formation in Northern Alberta. The experiments were also modeled by the CFD to better understand the flow dynamic near the liner.

Results of the analytical model and experimental tests were generally in agreement. However, results of the analytical model deviate from experimental tests for narrow slots and high flow rates. In these cases, the analytical model predicts smaller skin than the experimental tests. For cases related to narrow slots and higher velocity the pore plugging close to the liner is significant which was not modeled in the analytical model. Moreover, for very fine sand (low permeability) sand-pack the deviation from the experimental results is higher in comparison with medium uniform sand (higher permeability) sand-pack. CFD simulations showed the effect of the slot width on the depth of the convergence zone, which is not included in the analytical model. Since the analytical model follows the experimental results for common flow rates in thermal production, the model could be used to assess the skin for different possible designs and choose the best slot specifications that minimize the skin.

This paper presents the details of an analytical model for the skin factor verified by experimental data and CFD simulation. This analytical model can be used to optimize the liner specification for the best flow performance. This paper also outlines the limitations of the analytical models for calculation the skin/pressure drop.

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2017

Authors: Vahidoddin Fattahpour (University of Alberta) | Vittor Maciel (University of Alberta) | Mahdi Mahmoudi (University of Alberta) | Ken Chen (University of Alberta) | Alireza Nouri (University of Alberta) | Michael Leitch (RGL Reservoir Management)

There is a growing interest in physical model testing of the reservoir and large-scale sand control testing for oil sands. These experiments require the synthesization of representative sand-packs. Particle size distributions (PSDs) of these sand-packs ought to be comparable to the PSD of target oil sands. For practical and economic reasons, it is favorable to test samples with a limited number of PSDs, yet representative of a spectrum of oil sands. The aim of this paper is to categorize the PSD of Alberta oil sands to a limited but representative number for use in laboratory research.

This paper is based on the analysis of 152 PSD curves for Alberta oil sands. To categorize these PSD's in a meaningful way, an algorithmic approach is presented which uses attributes that are widely used in sand control design (e.g. D10, D50, D70, fines content) and, subsequently screens and sorts the data to produce a finite number of PSD categories which represent the majority of the data. Rules are implemented in the algorithm to limit the number of categories (≤7), and require that each category cover a significant subset of the total data (≥10%).

A review of the published PSDs for oil sands across Alberta indicates a significant variation in the PSD curves even within the same reservoir. However, in spite of the fact that PSD data show a large variation, PSD categories can be identified to build representative oil sand samples for design and testing purposes. For the database used in this investigation, four major and two minor PSD classes were identified. These six PSD classes, cover more than 87% of the analyzed PSDs. Introduced classes and existing PSD classifications in the literature share interesting similarities. However, certain differences, such as the lack of very coarse ranges (D50~500 µm) was observed.

The method which is introduced for oil sand classification is based on the D-values which are commonly used in screen aperture design. This method provides a useful tool for both screen designers and researchers to categorize and focus their work on a specific set of representative PSDs, rather than a wide distribution of PSDs.

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2017

Authors: Mahdi Mahmoudi (University of Alberta) | Vahidoddin Fattahpour (University of Alberta) | Alireza Nouri (University of Alberta) | Michael Leitch (RGL Reservoir Management)

This paper presents the results of an experimental investigation to determine the mechanisms of pore plugging and permeability reduction near SAGD screen liners. The aim is to arrive at a liner design that maximizes wellbore productivity without compromising the sand control function of the liner.

We set up a large-scale Sand Retention Testing (SRT) facility that accommodates a multi-slot liner coupon at the base of a sand-pack with representative grain shape and particle size distribution (PSD) of typical oil sands. Brine is injected at different flow rates and pressure differences across the coupon and the sand-pack as well as the mass and PSD of the produced sand and fines are measured during the test. Further, the PSD and concentration of migrated fines (<44 microns) along the sand-pack are determined in a post-mortem analysis. The testing results are used to assess the effect of slot size and slot density on the sand control performance as well as pore-plugging and permeability alterations near the sand-control liner.

We observed that the slot size, slot density and flow rate highly affect the concentration and PSD of produced fines as well as accumulated fines (pore clogging) above the screen. For the same flow rates and total injected pore volume, wider screen aperture and higher slot density result in lower fines accumulation above the screen but more sanding. Further, the variation of slot density alters the flow convergence behind the slots, hence, the size and concentration of mobilized fines. Results indicate that higher fines concentration near the screen reduces the retained permeability, hence, lowers the wellbore productivity.

This paper provides a new insight into pore plugging and fines migration adjacent the sand control liner. It also introduces a new testing method to optimize the design of sand control liners for minimum productivity impairment in SAGD projects.

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2016

Authors: Mahdi Mahmoudi (University of Alberta) | Vahidoddin Fattahpour (University of Alberta) | Alireza Nouri (University of Alberta) | Ting Yao (the University of Hong Kong) | Beatrice Anne Baudet (the University of Hong Kong) | Michael Leitch (RGL Reservoir Management Inc.) | Brent Fermaniuk (RGL Reservoir Management Inc.)

This paper presents the results of several large-scale Sand Retention Tests (SRTs), which are used to test and refine the criteria used for slotted liner design. The paper also presents the analysis of test measurements to improve the understanding of the parameters that influence the sand control performance. The parameters include Particle Size Distribution (PSD), flow rate, slot opening size and slot density.

The SRT facility was commissioned to improve the existing testing methods by (1) using multiple-slot rather than single-slot coupons, (2) using more realistic sand pack preparation/saturation procedures than the existing practices, (3) measuring the pressure drop along the sand pack and across the liner coupon to assess the retained permeability and flow convergence, and (4) post-mortem analysis of the sand pack to measure fines/clay content along the sand pack as a direct measure of fines migration. Several tests were performed by varying the slot size, slot density, and PSD of the sand pack, and flow rate. The testing data were used to validate and improve the current industrial design of slotted liners.

Test measurements and observations indicate that the sand pack preparation procedure highly affects the testing results. For typical field porosities and PSDs, we observed finite amount of sand production bellow the existing criteria for sanding during the SRT, for the screens designed based on existing models. Testing data also indicate smaller retained permeability for lower slot density due to converging flow. Moreover, measurements indicate lower retained permeability for narrower slot width, caused by the accumulation of fines and pore plugging in the liner's vicinity. However, larger slot width than a certain size contributes to higher levels of sanding. Three different sanding modes are identified: (1) initial sanding or sand occurrence, (2) flow rate dependent transient and (3) flow rate dependent continuous sanding. It is proposed that the sanding mode should be also included in the design criteria along with the acceptable sanding threshold. Test results indicate the combined effect of the slot size and density on both retained permeability and sand production. These findings lead to a new design approach for maximum retained permeability and acceptable sand retention.

This paper introduces a new set of design criteria for slotted liners based on the results of a novel large-scale testing to evaluate the sand control for thermal heavy oil production applications. Also it provides a better understanding of the sand production and the role of the slot width and slot density on the sand production. The paper also presents an improved understanding of the sanding and permeability evolution close to the liner in relation to several liners and flow parameters. The set-up, testing procedures, and measurement methods that are used in the experiments improve the existing methods in several fronts.

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2016

Authors: Vahidoddin Fattahpour (University of Alberta) | Saman Azadbakht (University of Alberta) | Mahdi Mahmoudi (University of Alberta) | Yujia Guo (University of Alberta) | Alireza Nouri (University of Alberta) | Michael Leitch (RGL Reservoir Management Inc.)

In SAGD wells, the gap between the oil sand and the sand control liner closes or collapses over time due to such factors as the oil sand thermal expansion, the melting of bitumen and the ensuing loss of the apparent bonding between the grains. The result is the buildup of effective stresses and the gradual compaction of the oil sands around the liner. Current practices for the sand control design do not account for the effect of time-dependent effective stress variation around the liner on the sand control performance. In this paper, we outline the results of an experimental study on the effect of near-liner effective stress on the performance of slotted liners.

This study builds on existing experimental procedures and investigates fines migration, sand production and clogging tendency of slotted liner coupons in large-scale unconsolidated sand-packs. Sand-packs with controlled properties (grain size distribution, grain shape, and mineralogy) are packed on a multi-slot sand control coupon in a triaxial cell assembly. Varying levels of stress are applied to the sand-packs in directions parallel and perpendicular to the multi-slot coupon. For each stress level, brine is injected into the sand-pack from the top surface of the sample towards the coupon. Test measurements include pressure drops across the sand-pack and the coupon as well as the produced sand/fines mass for each stress level. Post-mortem analysis is performed to measure fines/clay concentration along the sand-pack as a direct measure of fines migration.

Experimental results show that under the subsequent increase in effective stresses, sand-packs experience considerable deformations in directions parallel and perpendicular to the multi-slot coupon; which result in a drastic drop in the porosity and retained permeability. Test results show that the maximum reduction in permeability occurs in the vicinity of the multi-slot coupons due to the fines accumulation and the higher compaction in that region. In comparison to experiments with no confining stress, the application of confining stress results in lower retained permeability in the sand-packs as well as reduced sand production.

This paper presents, for the first time, the effect of near wellbore effective stress on clogging tendency and sand retention characteristics of slotted liner completions. The tests allow the assessment of the adequacy of the use of existing design criteria over the life cycle of the well under variable stress conditions around the liner.

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2016

Authors: Mahdi Mahmoudi (University of Alberta) | Vahidoddin Fattahpour (University of Alberta) | Alireza Nouri (University of Alberta) | Saad Rasoul (University of Alberta) | Ting Yao (The University of Hong Kong) | Beatrice Anne Baudet (The University of Hong Kong) | Michael Leitch (RGL Reservoir Management Inc.) | Mohammad Soroush (University of Trinidad and Tobago)

This paper presents the characterization of oil sands from the McMurray Formation. The main objective of this paper is to investigate the possibility of replicating the oil sands by the mixtures of commercial sands and fines for large-scale testing. There is a growing interest in large-scale evaluation testing for sand control devices that require considerable amounts of representative oil sands materials. However, natural representative oil sands samples are usually not available or are limited in quantity. Therefore, replicating the oil sands is essential for such tests.

Twenty-three oil sands samples were collected from two wells in the McMurray Formation and cleaned using the Soxhlet extraction technique. The cleaned samples were examined using the image analysis technique and Scanning Electron Microscope (SEM) imaging to study their Particle Size Distribution (PSD), shape factors, mineralogy, and texture. Similar analysis was performed on eleven series of commercial sands to compare their shape, mineralogy, and texture with those of oil sands. Particle Size Distribution of 10 commercial fines was also analyzed with a particle sizer to cover the required fine/clay part of the duplicated samples. Direct shear and 1D consolidation were performed to compare the mechanical properties of the oil sands samples and the duplicated mixtures of commercial sands and fines.

The shape factors of the oil sand and the selected commercial sand samples are in close agreement. In addition to the common average/cumulative shape factor measurements, this paper also presents the variation of shape factors within each sample for different grain sizes. The results show the same sand shape characteristics among all oil sand samples as well as the tested commercial sands. Further, XRD results indicate a similar mineralogy for the commercial sands and the oil sands samples. The SEM images show random changes in the surface texture of both oil sands and commercial sands with no observable trends. We were able to use commercial sands and fines mixture with similar grain shape properties to duplicate the PSD of the oil sand samples. Direct shear and 1D consolidation testing of the oil sands and samples made of commercial sands and fines show similar consolidation and frictional properties for both the duplicated mixture and cleaned oil sands for the same compaction level (porosities).

This paper provides a procedure for duplicating the oil sands with commercial sands and fines. It also provides detailed information on the mineralogy, texture, and the variation of the shape characteristics for oil sands from the McMurray Formation.

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2016

Authors: Fattahpour, Vahidoddin & Mahmoudi, Mahdi & Nouri, Alireza & Leitch, Michael. 

Several sand control techniques have been used in SAGD wells in Western Canada. For most projects, slotted liner has been the sand control of choice for its economics, ease of use, and acceptable performance. Careful design of the slot geometry is crucial to maintain long term wellbore performance but is not an easy task in formations with high fines content and other challenging characteristics, such as in Grand Rapids or shore-face at the upper member of McMurray. The objective in the design of sand control is generally to minimize the production of sand and maximize the retained permeability in the liner’s vicinity by allowing the production of any mobilized fines, avoiding extreme pressure drops by minimizing the curvature of flow streamlines around the slots, and avoiding the plugging of slots over time. Design practices for sand control in SAGD wells are currently based mostly on Particle Size Distribution (PSD) and the fines (<44um) content. Where designers focus principally on retaining sand rather than maximizing the retained permeability in the liner’s vicinity, there is an increased risk of underperforming completion designs, but long term well performance requires a reasonable tolerance for solids production. This paper provides a critical review of existing design criteria and the experimental testing and techniques for assessing the sand control design for SAGD production wells. It reviews the mechanisms which cause sand production and fines migration in relation to the PSD of oil sands and the formation clay and silt content. In addition, the paper presents field failure cases from the literature and examines the common problems with different types of sand control. Finally, practical recommendations are presented to further improve the current design criteria and sand control experiments to achieve higher productivity index, lower skin buildup, and greater durability of sand control screens.

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2016

Authors: Mahdi Mahmoudi, University of Alberta; Vahidoddin Fattahpour, University of Alberta; Alireza Nouri, University of Alberta; Saad Rasool, University of Alberta; Michael Leitch, RGL Reservoir Management Inc.

The quantification of fines migration in the vicinity of sand control screens in SAGD wells is of paramount importance to operating companies, who require the wells to operate under optimum conditions for a period of 10-15 years. Fines migration can lead to the plugging of pore spaces around the liner and result in reduced permeability in the liner’s vicinity, hence, lowering the wellbore productivity. This paper investigates the fines migration in relation to slot width and density in SAGD wells. A series of laboratory experiments was performed by using a Sand Retention Testing (SRT) facility which accommodates a sand pack sample and a multi-slot coupon to represent the near-wellbore high-porosity zone and sand control liner, respectively. As fluid was pumped through the sand pack and across the slotted coupon, the pressure drop across the sand pack and coupon was measured, along with the mass and Particle Size Distribution (PSD) of produced fines and sand. After the flow test, the sand pack was dissected, and the PSD of fines portion of sand pack was measured to assess the movement and concentration of fines over the course of the test. Test observations indicate that the slot width, slot density, and the flow rate highly affect the fines migration/production and the PSD of the migrated and produced fines. Larger slot widths increase the mass of the produced and migrated fines. Further observations indicate that the mass and size of produced fines is highly dependent on the flow rate and that there is a critical rate below which little amounts of fines are produced or move in the porous medium.


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2016

Authors: Mahdi Mahmoudi (University of Alberta) | Vahidoddin Fattahpour (University of Alberta) | Alireza Nouri (University of Alberta) | Michael Leitch (RGL Reservoir Management Inc.)

In this paper, we present the results of an experimental investigation on the effect of pH and salinity on slotted liner performance in terms of sanding and retained permeability for heavy oil thermal production. This work is an advancement of the existing knowledge in the literature which indicates that pH and salinity could highly affect the mobilization, flocculation and deflocculating of clays (mainly Illite and Kaolinite) in oil sands formations.

Water with different pH, in the range of 6.8 to 8.8, and salinities, in the range of 0 to 1.4 % was injected into sand pack samples supported with multi-slot coupon in a Sand Retention Testing (SRT) facility. Measurements included pressure drops along the sand pack and across the slotted liner coupon as well as the produced sand/fines for different flow rates. These measurements were used to assess the effect of the pH and salinity on fines migration within the sand pack, capability of the slotted liner to produce the fines, pore and slot plugging, sand production and the retained permeability.

We observed that the pressure drops, fines production and the retained permeability are highly dependent on the pH and salinity of the injected fluid. In low pH and high salinity environment, clay is not mobilized resulting in low pressure drops and high retained permeabilities. On the other hand, an increase in pH value or a decrease in salinity leads to significant clay mobilization and a remarkable reduction in retained permeability.

This paper provides a thorough experimental investigation of the pH and salinity effect on slotted liner performance. The effect of the pH and salinity is usually ignored in screen control testing while it could highly control the clay mobilization and retained permeability. Results of this study could trigger wide reconsideration in sand control approaches particularly by altering the pH in the near wellbore zone.

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2015

Authors: Mahdi Mahmoudi (University of Alberta) | Vahidoddin Fattahpour (University of Alberta) | Alireza Nouri (University of Alberta) | Ting Yao (University of Hong Kong) | Beatrice Anne Baudet (University of Hong Kong) | Michael Leitch (RGL Reservoir Management Inc.)

Oil sand characterization tests are essential for the selection and evaluation of sand control devices. Current approaches for screen selection and evaluation usually rely on Particle Size Distribution (PSD) and neglect the effect of important parameters such as porosity, grain shape and frictional properties. One aim of this study is to characterize oil sand's mechanical, geometrical and size characteristics that should be considered in the completion design. Another objective is to determine if natural mixture of oil sand could be reasonably replicated with commercial sands for large-scale sand control evaluation tests.

In this paper we present the results of a comprehensive image analysis and laser sieve analysis on oil sand samples from the McMurray Formation to quantify geometrical grain characteristics (sphericity, aspect ratio, convexity and angularity) of the sand grains and establish the PSD of the samples. Direct shear tests were performed to assess the frictional characteristics of different oil sands around the liner under variable stress conditions during the SAGD well lifecycle.

Image analysis, PSD, and direct shear tests showed that natural mixture of oil sand could be successfully simulated with commercial sands in terms of size and shape of grains and mechanical properties. This conclusion is significant to those performing large-scale sand control evaluation tests that usually require large quantities of sands that are not readily available and require significant preparation.

This paper provides the first comprehensive investigation of the granular, and geomechanical characteristics of oil sand from the McMurray Formation. The paper discusses the missing parameters in the design of sand control device, and evaluates test methods that measure those parameters. The proposed testing program could be used as a benchmark for oil sand characterization in relation to the design and evaluation of sand control device.

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Computational Fluid Dynamics
2019

Authors: Miguel A. Balzan, Franz Hernandez, Carlos F. Lange, Brian A. Fleck


The bubble formation frequency from a single-orifice nozzle subjected to the effects of a crossflowing liquid was investigated using high-speed shadowgraphy, combined with image analysis and signal processing techniques. The effects of the nozzle dimensions, orientation within the conduit, liquid cross-flow velocity, and gas mass flow rate were evaluated. Water and air were the working fluids. Existing expressions in the literature were compared to the experimental values obtained. The expressions showed modest agreement with the experimental mean average frequency magnitude. It was found that increasing the gas injection diameter could decrease the bubbling frequency approximately 12% until reaching a certain value (0.52 mm). Further increasing the nozzle dimensions increase the frequency by around 20%. Bubbling frequency is more sensitive to the liquid velocity where changes up to 63% occurred when the velocity was raised from 3.1 to 4.3 m/s. Increasing gas mass flow rates decreased the gas jet breakup frequency in all cases. This phenomenon was primarily attributed to changes in the bubbling mode from discrete bubbling to pulsating and jetting modes. The nozzle orientation plays a role in modifying the bubbling frequency, having a higher magnitude when oriented against gravity.

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2018

Authors: M. Miersma (University of Alberta) | M. Mahmoudi (RGL Reservoir Management) | V. Fattahpour (RGL Reservoir Management) | L. Li (University of Alberta) | C. F. Lange (University of Alberta)


In steam injection thermal recovery, it is essential to have a uniform flow to improve the recovery and to avoid the localized steam breakthrough which could lead to damage to well completion. In this paper, we propose three quantitative criteria to assess the performance of inflow control devices (ICD) based on computational fluid dynamics (CFD) modeling. The new performance criteria are exemplified in the evaluation of a few basic ICD designs.

To evaluate the response of the ICD to flow rate and fluid type, three new performance criteria, defined as (1) quadratic flow coefficient, (2) viscosity coefficient, and (3) erosion potential, are proposed and evaluated based on a set of CFD simulations. The first criterion measures the flow rate response and the ability of the ICD to restrict high velocity flow, the second quantifies the viscosity sensitivity, and the third predicts the potential for erosion in the device.

Four different liner deployed ICD designs, based on two passive design types (nozzle and channel) and one autonomous design type (Tesla flow diode), were analyzed using a rigorous CFD model. The model includes the surrounding slotted liner and inner tubing to identify any interactions of the ICD with the surrounding completion. The CFD model has been verified for grid and domain independence and it was applied to a range of flow rates representative of the field condition. In addition, simulations were run for a range of single-phase incompressible fluids with varying viscosities.

Using the newly proposed criteria, the ICDs were evaluated and compared. The comparison shows that, of these devices, the diode does the best job of restricting the flow at high flow speeds and low viscosities. At high viscosities, such as in the case of oil, the diode is the least restrictive device. Although the two straight nozzles tested are slightly worse at restricting the flow, they have the lowest erosion potential. Based on this comparison and the proposed criteria, the channel design performs poorly. At low viscosities it does not sufficiently restrict the flow, and at high viscosities it overly restricts the production of oil. It also has a high erosion potential, because of the steep entrance angle.

In this work, a new set of quantifiable criteria are defined and assessed that allow multiple aspects of different ICD designs to be compared simultaneously. Overall, these three criteria give a highly sensitive, quantitative means of comparing ICD designs. With these three criteria together, a more comprehensive comparison can be made in support of selection and improvement of ICDs.

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2018

Authors: Li, Lei & Lange, Carlos & Ma, Yongsheng

Multiple-view feature modeling is supposed to keep the information consistency during product development. However, for products involving fluid flow, the information consistency is difficult to keep because the application of CFD (Computational Fluid Dynamics) requires specific knowledge and rich experience. To conquer this deficiency, an expert system is proposed to update the CFD analysis view in response to the changes in the design view which is embedded in the CAD fluid functional features. The CAE interface protocol is used to convert the features in the design view into the CAE boundary features in the CFD analysis view. The CFD analysis view also includes the fluid physics features and dynamic physics features which constitute the expert system. The expert system is enhanced with the capability to model complex turbulent phenomena and estimate the discretization error. A case study of contracted pipe is illustrated to show the effectiveness of the proposed multiple-view feature modelling method by comparing with empirical results.

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2017

Authors: Lei LiCarlos F LangeYongsheng Ma


Computational fluid dynamics has been extensively used for fluid flow simulation and thus guiding the flow control device design. However, computational fluid dynamics simulation requires explicit geometry input and complicated solver setup, which is a barrier in case of the cyclic computer-aided design/computational fluid dynamics integrated design process. Tedious human interventions are inevitable to make up the gap. To fix this issue, this work proposed a theoretical framework where the computational fluid dynamics solver setup can be intelligently assisted by the simulation intent capture. Two feature concepts, the fluid physics feature and the dynamic physics feature, have been defined to support the simulation intent capture. A prototype has been developed for the computer-aided design/computational fluid dynamics integrated design implementation without the need of human intervention, where the design intent and computational fluid dynamics simulation intent are associated seamlessly. An outflow control device used in the steam-assisted gravity drainage process is studied using this prototype, and the target performance of the device is effectively optimized.

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2017

Authors: Lei LiC. F. LangeYongsheng Ma


Multi-view feature modelling provides a specific view for each phase in product development. The analysis view should be fully integrated with CAD models in a multi-view product development environment for simulation-based design. In the development of fluid flow products, CFD (Computational Fluid Dynamics) is increasingly used as an advanced support. However, the successful application of CFD requires special knowledge and rich experience, which is a barrier for the conversion from the design view to the analysis view, and the maintenance of information consistency. Several approaches to multiple feature views have been proposed, such as design by features, feature recognition and feature conversion. In one-way feature conversion, features in a specific view are usually derived from the original design view. Bronsvoort and Noort put forward a multiple-way approach which enables a designer to modify the product model from an arbitrary view. In this paper, the CAE interface protocol is used to convert the features in the design view into the CAE boundary features [5] in the analysis view. Based on the physical knowledge, an expert system is established to further process those features and generate a robust simulation model with the help of fluid physics features and dynamic physics features in the analysis view.

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2017

Authors: Matthew Miersma


One of the main methods of extracting oil from deep oil sands deposits is through the use of steam assisted gravity drainage (SAGD). For the best performance, inflow control devices (ICDs) are implemented along the SAGD production well to even out production and restrict unwanted fluids. Current methods of evaluating these devices rely on criteria that are dependent on the flow rate and fluid properties at which they are measured. In this study, three new criteria are proposed to evaluate and compare ICDs. These new criteria are derived from the physics of the flow in order to tie them to specific aspects of the flow and to have a reduced dependence on the flow rate and fluid properties. To further reduce the dependence of the criteria, they are calculated from a range of data, using a least squares fit. In order to evaluate the proposed criteria, detailed CFD models are developed for six fundamental ICD designs: a 15◦ nozzle, a 40◦ nozzle, a long channel, an expanding nozzle, a device based on Tesla’s fluidic diode, and a vortex based device. The CFD models are carefully tested to ensure they accurately model the flow. Using these simulations, the three criteria are calculated for each device. The criteria are then compared to the flow results and examined for flow and viscosity independence. Finally, the criteria are used to compare the six ICDs and identify the best design. The new criteria are not only better than existing criteria for comparing ICDs, but they are also specially adapted to support design development and optimization of new devices.

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2017

Authors: Li, Lei & Ma, Yongsheng & Lange, Carlos


The complexity in configuring the CFD solver imposes a barrier for users to efficiently setup the solver and obtain satisfactory results. Such kind of deficiency becomes more obvious when it comes to simulation-based design where the CFD solver is expected to respond to design changes automatically. By applying artificial intelligence, expert systems can be used to capture the knowledge involved in CFD simulation and then assist the solver configuration. This paper proposes an expert system for both dry and wet steam simulation. According to the product design, the expert system is able to select the right module to model the steam flow. Based on the derived non-dimensional numbers, appropriate physics models can be selected to run the simulation. Grid adaption, higher order schemes, and a subroutine for advanced turbulence models help to improve the accuracy of the CFD model after rounds of simulation. The output of the expert system is a robust simulation model with accurate results which are guaranteed by flow regime validation, grid independence analysis, and error estimation. The effectiveness of the proposed system is demonstrated by the analysis of a contracted pipe. In dry steam simulation scenario, the error induced by the expert system is smaller than that of the traditional ANSYS batch mode. The results obtained by the expert system also match well the empirical results when it comes to wet steam simulation.

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2016

Authors: Lei Li, Yongsheng Ma, Carlos F. Lange


CFD (Computational Fluid Dynamics) requires strong expertise and extensive training to obtain accurate results. To improve the usability in the complex product development process, two new types of engineering features, fluid physics feature and dynamic physics feature, which convey the simulation intent, are proposed in this paper to achieve CFD solver setup automation and robust simulation model generation in an ideal CAD/CAE integration system. Further, the association between simulation intent and design intent is integrated with another newly defined fluid functional feature in order to achieve the consistency. Consequently, an optimal design could be achieved by considering production operation, manufacturability and cost analysis concurrently. A case study of steam assisted gravity drainage (SAGD) outflow control device (OCD) is presented to show the prospective benefits of the method.

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2016

Authors: Li, Lei & Lange, Carlos & Ma, Yongsheng.

Outflow Control Device (OCD) is applied in Steam Assisted Gravity Drainage (SAGD) to control the steam split to the formation from the injection well. The detailed analysis of OCD with CFD is desired to obtain comprehensive understanding of the flow in the device and guide design optimization. The simulation presented here is based on a commercial OCD product applied in industry. With ANSYS/CFX TM , the simulation research was carried out by phases. According to the analysis of OCD application conditions, the simulation of a small quarter domain is conducted to test the boundary conditions and the OCD flow behavior corresponding to different pressure drops. The steam distribution is believed to have an effect on the efficiency of heating. To evaluate the effect of different design on steam distribution, the simulation of half domain with different gap sizes was further processed; two parameters have been identified to quantify the steam distribution. A simulation scenario of a 360°domain is introduced at last to discover the interaction between the steam flowing through the four orifices.

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2016

Authors: Lange, Carlos & Ma, Yongsheng.

CFD (Computational Fluid Dynamics) requires strong expertise and extensive training to obtain accurate results. To improve the usability in the complex product development process, two new types of engineering features, fluid physics feature and dynamic physics feature, which convey the simulation intent, are proposed in this paper to achieve CFD solver setup automation and robust simulation model generation in an ideal CAD/CAE integration system. Further, the association between simulation intent and design intent is integrated with another newly defined fluid functional feature in order to achieve the consistency. Consequently, an optimal design could be achieved by considering production operation, manufacturability and cost analysis concurrently. A case study of steam assisted gravity drainage (SAGD) outflow control device (OCD) is presented to show the prospective benefits of the method.

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2015

Steam Assisted Gravity Drainage (SAGD) has been applied as a reliable oil recovery technology in the oil sand industry. In order to increase the productivity of the SAGD process, Outflow Control Devices (OCD) are used to control the injection of steam into the formation. Our work aims at the modelling of OCD with Computational Fluid Dynamics (CFD). In this paper, CFD simulation of OCD has been done based on a simplified model. The mechanism how OCD controls the flow is studied through a series of test simulations. Different models have been compared to study the effect of the setup details on the OCD flow. In the future, more accurate models will be established evolving from the results obtained currently and further investigation to be done into the problem.

 

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