Brand: Variperm

A Novel sand control testing facility to evaluate the impact of radial flow regime on screen performance and its verification

Authors: M. Haftani, O. Kotb, P. H. Nguyen, Chenxi Wang, Mahmood Salimi, Alireza 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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Design for Reliability: Purpose Driven Sand Control Methods for Cased and Perforated Wells

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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Measurement of the flow behavior index of Newtonian and shear-thinning fluids via analysis of the flow velocity characteristics in a mini-channel

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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Advances in Understanding the Scaling Potential for Thermal Wells: A Mechanistic Study

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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Fiber Optics Application for Downhole Monitoring and Wellbore Surveillance; SAGD Monitoring, Flow Regime Determination and Flow Loop Design

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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Development of a Rigorous Erosion Prediction Physical Model for Thermal Standalone Sand Control Screens

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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Standalone Sand Control Evaluation: Developing a Large-Scale High Temperature Sand Retention Test Apparatus

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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Hybrid intelligent algorithm for permeability estimation based on PSD and porosity data

Permeability is one of the most important features for reservoir characterization. The correlation between permeability versus particle size distribution (PSD) and porosity is widely acknowledged in oil-sand reservoirs. PSD is a main physical property in oil-sands, and it is an important variable in many complex hydrological, geological, and geophysical processes. Developing a relationship for permeability estimation based on such fast-gathering and low-cost data, namely PSD and porosity measurements, offers a cost-effective alternative for permeability predictions, as well as surveying permeability variations in a large-scale study. In the literature, many investigations have been carried out for developing a relationship between permeability versus PSD and porosity (Arshad et al., 2019). However, the literature lacks the application of machine learning algorithms in developing such relationship.

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Experimental and analytical investigation of meso-scale slug bubble dynamics in a square capillary channel

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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Experimental Correlations for the Performance and Aperture Selection of Wire-Wrapped Screens in Steam-Assisted Gravity Drainage Production Wells

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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