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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper
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.
Download paper