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

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. 

Download paper

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.

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: 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: 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: 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: 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