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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Authors: Azadi, Reza & Wong, Jaime & Nobes, David
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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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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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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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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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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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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