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NCG is increasingly being co-injected with steam in heavy oil production systems to reduce heat loss and greenhouse gas emissions, as well as to maintain reservoir pressure. Given increased use of NCG co-injection, the validity of conventional subcool models must be revisited since they assume that the steam chamber is comprised of water alone. The current study makes modifications to the pure-steam hydrostatic subcool model, as well as the Yuan & Nugent (2013) subcool model to account for the presence of NCG in the steam chamber. Using typical values from the Athabasca oilfield, the study then compares the liquid-height predictions made by the original and modified models and proposes rules-of-thumb that correct for the presence of NCG. In general, increasing NCG in the steam chamber results in a reduction in subcool relative to pure steam. According to modified hydrostatic model, to achieve a liquid-pool height equal to that of pure steam injection, the subcool must be increased by 0.60K per 1% increase in the vapor-phase molar fraction. In contrast, over a wide range of production rates and drawdowns, the modified Yuan & Nugent (2013) model predicts that to achieve a liquid-pool height equal to that of the pure steam case, the subcool must be increased by 0.66K per 1% increase in the vapor-phase molar fraction. Despite the rule-of-thumbs being qualitatively in line with expectations, they suffer from the inability to accurately calculate subcool from field data. The final section of the paper reviews limitations of subcool as a well performance metric and proposes an alternative method of assessment that relies on data that are more readily available to operators.

In steam-assisted gravity drainage (SAGD) operations, inflow control devices (ICDs) might provide an extra pressure drop (ΔP) on top of the liquid pool's ΔP. To avoid hot-spot zones, this ΔP design heavily relies on reservoir quality. Flow-loop experiments can provide flow قate measurements versus ΔP for various nozzle designs. Therefore, an efficient ICD design should be investigated in a numerical flow simulation that represents reservoir quality and heterogeneity by employing flow-loop data.In this study, core analysis and 40 PSD data drilled in the same location are collected, and permeability for each PSD is estimated using a correlation developed in our previous study. Given PSD offers a measure of hydraulic properties and heterogeneity, it can provide an indirect indicator of potential hot-spot zones. Moreover, representative PSDs are determined by using a clustering algorithm to tie the best-designed ICD to the relevant geology. The reservoir model for the database's location is generated using real data, three tabular data from flow-loop experiments are assigned to the reservoir simulation, and the ICDs' performances are compared.The clustering algorithm generated five groups with a weighted average permeability of 4,013 mD. The first and second largest clusters with 6.55% and 35.05% fines content cover 55% and 23% of the database, respectively. By employing a relatively conservative production with subcooling between 10°C and 15°C, the cases with liner deployed (LD) ICDs offered a greater oil production rate, better steam conformance, and lower cumulative steam oil ratio (cSOR) than the cases without ICDs. However, in a rather risky production scenario with subcool between 1°C and 5°C, the case without ICDs could not be simulated in the desired the subcool temperature. Because of its enhanced steam conformance and slightly higher oil production rate, LDICD#1 was picked as the best case for the two scenarios. Compared to the case without ICDs, the oil production rate and cSOR for the case with LDICD#1 at higher subcool temperature rose by 17% and reduced by 8%, respectively. Compared to the case without ICDs, the oil production rate and cSOR for the case at lower subcool temperature with LDICD#1 raised by 21% and reduced by 12%, respectively.The findings demonstrate the effectiveness of ICDs at various subcool levels. The results could be applied in SAGD projects to reduce greenhouse gas emissions by reducing the water and natural gas usage to generate steam. Completion and production engineers would benefit from a better understanding of production relative performance to develop more effective operations design.

Various wellbore completion strategies have been developed for thermal wells in Western Canada. The idea in this paper is estimating the improvement of oil production and steam injection if flow control devices (FCDs) will be installed for the next wells to be drilled, or if FCDs were installed at a particular well-pad that has not yet been completed with any FCDs. The approach is based on labeled real data for 68 well-pads from seven major thermal projects in Western Canada. Three phases make up the paper's methodology. The first phase compares wells with and without FCDs to evaluate the performance of the FCDs based on normalized oil production and cumulative steam oil ratio (cSOR). The second phase involves clustering well-pads using an unsupervised incremental-dynamic algorithm. An estimation of FCD contribution to enhancing oil production and cSOR is also performed for test well-pads based on their most similar cluster. In the third phase, cross-validation is employed to ensure that the estimation is trustworthy, and that the procedure is generalizable. To evaluate the performance of FCDs, a reliable comparison was made using normalized oil production and cSOR. Based on our analysis from October 2002 to March 2022, successful FCD deployment resulted 42% more normalized oil and a 37% reduction in cSOR. Among these, liner deployed (LD) FCDs increased oil production by 44% while decreasing cSOR by 58%. Although tubing deployed (TD) FCDs are installed in problematic wells, they produced 40% more oil while decreasing cSOR by 21% in successful cases. Successful inflow control devices (ICDs) increased oil production by 40% while lowering cSOR by 45%. Successful outflow control devices (OCDs) increased oil production by 82% while reducing cSOR by 22%. The clustering algorithm separates the database into four clusters that will be utilized in the estimating phase. In the estimation phase, ten well-pads (15% of the database) are presumed to be new well-pads to be drilled (test data). Based on the estimation results, the root mean square errors (RMSEs) for FCDs contribution to enhancing oil production and cSOR for the test well-pads are 12%. Cross-validation was also performed to assess the approach's predictability for new data, to verify that our technique is generalizable. The findings indicate that FCDs might result in lower capital expenditures (CapEx) and greenhouse gas (GHG) emissions intensity for SAGD well-pad developments, allowing them to reduce emissions. The conclusions of this research will aid production engineers in their knowledge of relative production performance. The findings may be used to examine paradigm shifts in the development of heavy oil deposits as technology advances while keeping economic constraints in mind.

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.

Summary 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 preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion. In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory 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 is 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 effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage 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 at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop 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 completions. 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.

To investigate the effect of interaction between two single-Si3N4 particle-impingements on the repassivation of 304 stainless steel in a simulated groundwater, the corrosion current peaks of the samples during the impingement were recorded, and the micro-hardness of the substrate around the crater was tested. The results indicated that significant interactions between the two impingements were observed only when the value of distance-diameter ratio (L/d) was less than 1.5. With L/d being less than 1.5, the corrosion current peaks and mass losses due to the second impingements were higher than those of the first ones, and the re-passivation rates of samples during the second impingements were lower than those of the first impingements. Simultaneously, the microhardness of the substrate between the two craters was higher than that of the surface around one single crater with the same distance-diameter ratio. The mechanisms of how the L/d ratio influenced the interaction between the two impingements are also discussed.

SummaryPrevious studies showed that different parameters influence the plugging of completion tools. These parameters include rock mineralogy, reservoir-fluid properties, and type of completion tools. Although different methods have been used for unplugging these tools, there is still debate regarding the performance of these methods on damage removal. In this study, we assessed the performance of high-power shock waves generated from an electrohydraulic-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 quantified the extent of cleaning for the plugged slotted liners using the EHS tool at the laboratory scale. Next, we analyzed the mineral composition of the plugging materials removed after the treatment by conducting scanning electron microscopy (SEM) with energy dispersive X-ray spectroscopy (EDS), inductively coupled plasma mass spectroscopy (ICP-MS), colorimetric, and dry-combustion analyses. Finally, we reviewed the pulsing-stimulation-treatment results applied to several field case studies. The results of unplugging slotted liners at the laboratory scale showed that up to 28.5% of the plugged slots are cleaned after 120 pulses of shock waves. The mineral-characterization results showed that the main plugging materials are calcite, silicates, and iron-based components (corrosion products). The cleaning performance (CP) of the EHS tool increases by increasing the number of pulses and the output energy (OE) applied to the tool. The CP parameter is high at (i) high concentrations of carbonates, barium (Ba)-based components, and organic matter, and (ii) low concentrations of corrosion products and sulfates. The results of field case studies showed that the cleaning of the EHS tool is not limited to the sand-control devices and it can clean other tools that are less accessible for other techniques, such as subsurface safety valves. This paper provides a better understanding of the performance of shock waves on damage removal from plugged completion tools. The results could open new insight into the applications of shock waves for cleaning the completion tools.

Distributed Acoustic Sensing (DAS) through fiber optic has been deployed in downhole monitoring for over two decades. Several technological advancements led to a wide acceptance of this technology as a reliable surveillance technique. This paper presents a comprehensive technical review of all the applications of DAS. The paper starts with the fundamentals of fiber optic deployment. Then, an overview of all the applications of DAS including seismic application (vertical seismic profiling), microseismic (hydraulic fracturing characterization), well and pipe integrity (such as leak detection and cement quality), and well and pipe flow monitoring is provided. Flow monitoring contains injection and production flow estimation, phase determination, gas and water breakthrough identification, gas lift surveillance, pump and flow control device performance evaluation, sand production detection, and flow regime recognition. This paper reviews the basics of DAS, fiber types, installation methods, types of recorded data, data processing, historical development, current applications and limitations. The paper provides a concise review using several field cases from over two hundred published papers of Society of Petroleum Engineering (SPE) and journal databases. The applications of DAS in downhole monitoring can be generally divided into the qualitative and quantitative applications. The study discusses deployment methods, case by case worldwide field performance and interpretation/modeling. It also summarizes main lessons, key results, and challenges including data quality, signal to noise ratio effect, and operational conditions such as the installation of the fiber and the complexity of quantitative production prediction and flow profiling. In addition, a comparison between deployment of DAS and other methods is reviewed. This study is the foundation for an ongoing study on wellbore and reservoir surveillance through real time distributed fiber optic sensing (DAS) records along the wellbore. It summarizes the historical development and current limitations to identify the existing gaps and reviews the lessons learned during the two decades of the application of DAS in downhole monitoring.

Productivity of cased and perforated wellbores completed with standalone screen depends on the interactions of parameters such as perforation diameter, length, phasing and density, the gap between the casing and the standalone screen, and standalone screen aperture/pore size. Moreover, the permeability of the sand in the gap plays a major role in the overall productivity. This study aims at providing a numerical estimation of pressure drop for such completions. This study uses Computational Fluid Dynamics (CFD) in order to simulate the flow around a wellbore equipped with cased and perforated completion with standalone screen. Slotted liner was used as the standalone screen in this study. Details of such a complex completion were imported into the Finite Volume (FV) based numerical simulation via Computer-Aided Design (CAD). In addition to the geometrical design of the completion, different scenarios for the perforation stability, which affect the permeability of the perforation tunnel and result in potential fill-up of the annular gap between the slotted liner and perforations, were investigated. A large number of simulations (over 200 models) were completed to cover the different scenarios for perforation design and strategy along with different Open to Flow Area (OFA) values for the standalone slotted liner. Based on the results, completion efficiency is strongly changed by perforation and gap flow properties. The OFA for the standalone slotted liner completion has minor influence on the overall pressure drop if the gap between the casing and the standalone screen and the perforation is clean, unless the perforations are collapsed and the annular gap between the casing and slotted liner is filled up with sand. This is mainly because perforation parameters, such as penetration and diameter dominate the effect of all the other parameters, including slotted liner configuration. The results emphasize the effect of the completion geometry, perforation strategy, and opening size on the skin and productivity. Another main observation was the need to better understand the stability of the perforations and sanding potential from perforations, which dictate the permeability of the perforation and annular space. The results of this study highlight the comparative importance of different standalone screen designs and perforation parameters on well productivity. This study is the basis for optimizing the sand control and perforation strategy as an alternative to other completion types such as gravel packing in cased and perforated completions in vertical and slant wells.

Drilling the horizontal wells was the beginning of unlocking the enormous potential of Western Canada oil-sands. However, several technical and operational challenges avoid the so-called extended reach Steam Assisted Gravity Drainage (SAGD) wells. The last few years drive to reduce Capital Expenditures (CAPEX) encouraged the development of key innovative tools to make long thermal wells a reality. SAGD pad development using maximum possible well-length has taken significant leaps in economical assessment of SAGD projects. The goal of this paper is investigating the impact of Flow Control Devices (FCDs) on the overall performance of the long wells in SAGD projects. In this paper, seven major thermal projects in Western Canada were investigated. Production history of all the wells is normalized by the variation of the geological condition, operational parameters, and well length. Following a convention in the industry, the wells with lateral length longer than 850 meters are labeled as "long" and those shorter than 850 meters are labeled as "short". Eventually, normalized oil production by long wells completed or retrofitted with FCDs is compared with those without FCDs to supply insight on the role of completion design on relative performance of drilling long wells. The comparison has been conducted with respect to different completion types such as Liner or Tubing Deployed FCDs (LDFCD or TDFCDs). On average, long wells produced 2% more normalized oil compared to short wells for all projects, while they produced on average 16% more normalized oil in the projects 1, 2, 6, and 7 in which long wells successfully drilled. The historical production performances show that FCDs are the key enablers and innovative strategy to drill longer wells. For successful long wells with FCDs, the normalized oil production is improved as high as 81%, and the improvement rate is 108% and 10% for LD and TD FCDs, respectively. Furthermore, the completion strategy of combining long wells with FCDs improved the normalized oil production about 33% compared to short wells. This study shows that switching from short wells to long wells in SAGD projects and completing them with FCDs is a synergic approach to increase the oil production (33%). The results of this paper confirmed that drilling long wells with FCDs is a win-win strategy resulted in more oil production compared to long/ short wells without FCDs; since CAPEX is reduced by long wells and oil production is increased by FCDs. The results also help completion and production engineers to get a better understanding of the contribution of FCDs in long lateral wells.

SummaryDesigning 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.

Summary 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.

SummaryKazakhstan owns one of the largest global oil reserves (approximately 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 (PSD), clay content, porosity, permeability, gas cap, bottomwater, 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, the 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 true vertical depth) with oil viscosity of approximately 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 compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less-problematic conditions. Further investigation has shown that inflow-control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins 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.

Summary Sieve analysis, sedimentation, and laser diffraction (LD) 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. DIA, which is an advanced method of particle size and shape characterization, along with other PSD measurement methods, including sieving, sedimentation, and LD, were used 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 in the estimation of PSD and fines content, which are the primary factors important in 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. LD also tends to overestimate the fines fraction and underestimate silt/sand fraction compared with other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed that 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.

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 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.

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.

To solve the problems such as high denstiy, foam instability, low compressive strength, high porosity and poor durability associated with conventional foam cements, a novel colloidal gas aphron (CGA) based foam cement system was investigated and tested for properties. CGA is used in a base slurry as the foam component and the recipe was optimized with hollow sphere and micro-silica in terms of particle size distribution (PSD). Porosity, permeability, strength, brittleness, elasticity, free water content, foam stability and density tests on the CGA based foam cement system were carried out to evaluate the performance of the system. According to the experiment results, at the foam proportion of 10%, the cement density was reduced to 1 040 kg/m3, and stable microfoam net structure not significantly affected by high temperature and high pressure was formed in the cement system. The optimal CGA based foam cement has a free water content of 0%, porosity of 24%, permeability of 0.7×10−3 μm2, low elasticity modulus, high Poisson's ratio, and reasonable compressive strength, and is more elastic and flexible with capability to tolerate regional stresses. Key words: colloidal gas aphron, foam cement, light weight cement, compressive strength, well cementing

Steam Assisted Gravity Drainage (SAGD) is the dominant in-situ method for oil production in Western Canada. The current study analyzed the relative performance of various well-completion practices using data from 4,000 well pairs that were drilled over a decade. The data analysis provided a unique opportunity to find best operating practices. The scope of this paper is to review the performance of major thermal projects in Canada and investigating the effect of liner design and Flow Control Devices (FCDs) on well pair performance and development. Cumulative oil production and cumulative steam oil ratio (cSOR) were used as the key metrics in comparing the well performance in a SAGD operation. However, to compare different pads and different projects, it was critical to normalize the data with geological variation, well length, well spacing, and with consideration to the well failure rate, remedial completion and re-drills. In this paper we review seven thermal projects of four key operators with almost 3,500 wells and 1,200 well pairs in operation as early as 1996. All geoscience, and production/injection data have been extracted from public databases and utilized to develop a data-driven model. The reservoir thickness variation for each well was determined using available geoscience data, and through the development of a geological model based on the available core data and well logs. The model was used to define the drainage volume for each well pair, which in turn was used to assign a geological ranking to the well. The cumulative oil production and cSOR were then normalized with the geological ranking and the size of the net drainage volume. The number of well pairs in each pad and the cumulative pad production were normalized against the number of days in production and their relative decline, which allowed for comparison between pads within the same project, as well as pads from other projects. The cumulative production of the active pads in each project was used to compare the relative performance of different projects. Also, we separated the projects and wells based on their use of FCDs in the producer and injector to compare the relative performance of each technology in the field. This paper is the initial phase of the study on the role of completion design on relative well and well pad performance. The results will help completion and production engineers to better understand the well pair and pad relative performance and how to normalize the oil production data against geological variation to compare performance.

Intelligent systems are becoming more and more popular in the petroleum industry. Particle Size Distribution (PSD) based on sieve size is a key signature of the unconsolidated/weakly consolidated sandstone formations and is commonly the main parameter in the sand control design. With available extensive PSD measurement techniques and a large number of measurements, especially for horizontal wells, it is necessary to classify the PSDs prior to further analysis for the sand control design. On the other hand, PSD analysis is not enough for sand control design, and particle shapes need to be taken into account as well. A successful clustering algorithm for the mentioned purposes needs to be a cascade, multi-label, unsupervised and self-adaptive approach since the particles can be assigned to more than one group and there is no prior idea on how many clusters should be formed after the clustering process. Besides, due to the differences between sieve size and shape features, they should be used separately for clustering the particles. In the current study, a cascade approach is used for clustering the particles. In the first level of the cascade, an unsupervised and self-adaptive algorithm is introduced based on the sieve size features. The algorithm optimizes the number of clusters through a self-adaptive and incremental approach. The proposed clustering method uses a minimum similarity threshold (δ) as the only input parameter to start the clustering and tries to minimize the number of clusters during the clustering. In the second level of the cascade, the similarity between all particles in each cluster with their corresponding cluster-center is measured, and those particles that do not respect the δ in terms of the shape similarity, are moved out of the cluster. The novelty of the proposed method is in three folds. The first one is to provide a particle clustering algorithm, which works based on the whole range of the sizes and shape descriptors rather than focusing on certain points in the size graph (D-values). The second one is the dynamic nature of the clustering, which tends to optimize the number of clusters during the clustering process. The third one is that we have used a cascade approach for involving both size and shape parameters for the clustering. Our proposed method can be applied in field application for downhole monitoring and sand screen design.

Fouling is a critical issue faced by the chemical and oil industries in various operation processes, which has negative impact on the operational efficiency and generates significant economic losses, technical and environmental challenges. Investigating the interaction mechanisms between foulants (e.g., fine solids, asphaltenes) and different substrates is of both fundamental and practical importance in understanding the fouling mechanisms in chemical/petroleum engineering processes and developing antifouling strategies. In this work, atomic force microscope (AFM) colloidal probe technique was employed to directly quantify the interactions between silica or asphaltenes and selected substrates (i.e., carbon steel L80 and L80 with electroless nickel-phosphorus (EN) coating) in aqueous solutions. The effects of salinity, pH and presence of divalent ions (e.g., Ca2+) on the surface interactions were investigated. The obtained force profiles showed that the interactions between silica or asphaltenes and L80 surface were more attractive than that between silica or asphaltenes and EN coating, in NaCl solutions. Bulk fouling tests in silica and asphaltenes-coated silica suspensions revealed that significant fouling of silica and asphaltenes were found on L80 substrates, while EN coating exhibited excellent antifouling performance. Our results provide useful insights into the fundamental understanding of the fouling mechanism of fine solids and asphaltenes, and the development of novel effective antifouling coatings in chemical and oil industries.

Antifouling coatings have attracted much attention in applications of industrial equipment and systems. The accumulation of foulants on downhole equipment used in the steam-assisted gravity drainag...

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.

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.

Distributed Temperature Sensing (DTS) system using optical fiber has been deployed for downhole monitoring over two-decades. Several technological advancements led to a wide acceptance of this technology as a reliable surveillance technique. This paper presents a comprehensive technical review of all the applications of the DTS, with focus on oil and gas industrial deployments. The paper starts with the advantages of the DTS over other methods and an overview of the DTS basics, including theory, the DTS components, deployment types, fiber types, design and limitations. Then, it is followed by the oil and gas applications of the DTS including hydraulic fracturing (during and after fracturing), well treatment/stimulation (acid injection, fluid distribution, diversion monitoring), inorganic (scaling) and organic (wax/asphaltene/hydrate) deposition detection, leak detection (in well and pipeline), flow monitoring (rate monitoring, water/steam injection and SAGD monitoring, CO2 storage monitoring, zonal contribution determination, gas lift optimization) and reservoir/fluid characterization (facies, porosity, permeability and fluid composition determination). This study reviews the historical development, applications and limitations of the DTS systems. The paper mainly focusses on deployment techniques, the application of the DTS for the prediction and surveillance of the non-thermal and thermal producer/injector wells, hydraulically fractured wells and those wells with treatments. The paper provides a concise review using several field cases from over two hundred published papers of Society of Petroleum Engineering (SPE) and journal databases. The application of the DTS in downhole monitoring can be divided into the qualitative and quantitative applications. In quantitative approaches, numerical models should be combined with the DTS data. This study discusses case by case worldwide field applications of DTS along with proposed modeling methods and interpretations. It also summarizes main challenges, including the fiber reliability, longevity, and operational limitations such as the installation and the complexity of quantitative approaches. This study is the foundation for an ongoing study on wellbore and reservoir surveillance through real-time distributed fiber optic sensing recordings along the wellbore. It summarizes the historical development and limitations to identify the existing gaps and reviews the lessons learned through the two decades of the application of the DTS in production performance.

Development of weakly and unconsolidated sand reservoirs require effective sand control media to prevent sand production. The existing sand control devices in the market are either relying on surface filtration to prevent sand production through size exclusion or bridging or depth filtration which relies on the pore size distribution of a porous filter or pack to prevent the sand from producing along the production fluids. In this study, we introduce a new hybrid sand screen that works based on a combined surface and depth filtration.Radial Sand Control Evaluation (RSCE) testing facility was used to compare the solid production and flow performance of the new hybrid screen with various mesh media in multi-phase gas and liquid flow under various fluid injection scenarios. Solid production and flow performance were compared with investigated cases.The new hybrid screen provides an optimized Open to Flow Area (OFA) in comparison to available surface filtration or depth filtration media, which provides required OFA, while prevents sanding. The robust design, low cost and manufacturing ease make it a suitable screen media for most sand control applications. The sand retention test results under various fluid injection scenarios including multi-phase oil, brine, and gas show that it outperforms the Dutch Twill (DT) weave and Reverse Dutch Twill (RDT) weave of equivalent aperture size, with better flow performance at constant flow rate tests compare to best-performing mesh media, while keeping the produced sand far below the acceptable thresholds. Hybrid design handles both high velocity and high Gas-Oil Ratio (GOR) better than equivalent depth filtration media of equivalent size.This paper presents a detailed characterization, flow performance testing of a new hybrid sand control media that combines the surface filtration and depth filtration properties to achieve better solid retention and flow performance. The hybrid screen media is suitable for high-rate producers with high GOR.Keywords: Hybrid Screen, Surface Filtration, Depth Filtration, Radial Sand Control Evaluation (RSCE) Testing

In wake of the biggest oil crash in history triggered by the COVID-19 pandemic; Western Canada in- situ production is under tremendous price pressure. Therefore, the operators may consider shut in the wells. Current investigation offers an insight into the effect of near-wellbore skin buildup because of such shut-in. A series of simulation studies was performed to quantitatively address the impact of well shut-in on the long-term performance of well, in particular on key performance indicators of the well including cumulative steam to oil ratio and cumulative oil production. The long-term shut-in contributes to three main modes of plugging: (1) near-wellbore pore plugging by clays and fines, (2) scaling, and (3) chemical consolidation induced by corrosion. A series of carefully designed simulations was also utilized to understand the potential of skin buildup in the near-wellbore region and within different sand control devices. The simulation results showed a higher sensitivity of well performance to shut-in for the wells in the initial stage of SAGD production. If the well is shut in during the first years, the total reduction in cumulative oil production is much higher compared to a well which is shut-in during late SAGD production life. As the induced skin due to shut-in increases, the ultimate cumulative oil production drops whose magnitude depends on well completion designs. The highest effect on the cumulative oil production is in the case of completion designs with flow control devices (liner deployed and tubing deployed completions). Therefore, wellbore hydraulics and completion design play key roles in the maintenance of uniform inflow profile, and the skin buildup due to shut-in poses a high risk of inflow problem and increases the risk of hot-spot development and steam breakthrough. This investigation offers a new understanding concerning the effect of shut-in and wellbore skin buildup on SAGD operation. It helps production and completion engineers to better understand and select candidate wells for shut-in and subsequently to minimize the skin buildup in wells.

The design of Flow Control Devices (FCDs) requires performance data of an FCD’s internal nozzle under a wide range of flow scenarios. The current study specifically considers the effect of nozzle diameter and wall profile on the induced pressure loss, and subsequently the recovery performance of an FCD. For this study, a flow measurement facility is developed to test the performance of different orifice/nozzle geometries. The flow of single- and two-phase fluid at various flow rates and mass fractions, is experimented. The pressure drop data from the experiments is used to produce performance curves that characterize pressure loss across the geometries. The pressure loss for two-phase flows are compared to their single-phase counterparts to characterize the performance of the tested geometries in the two scenarios. A detailed protocol for performance testing of FCDs is followed as per Advanced Well Equipment Standard (AWES: recommended practice3362). The testing protocol was utilized to characterize the performance of different FCDs geometries under single- and two-phase flow conditions. The results showed the pressure loss characteristic obtained from the flow loop experiments match the corresponding theories. The study has thus provided promising results for the successful application of direct flow loop testing to obtain reliable data which can be used in FCD design, performance investigation, and reservoir simulation.

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.

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.

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.

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.

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.

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.

Previous studies have shown that different parameters such as reservoir conditions (e.g., pressure, temperature, and brine chemistry) and wellbore hydraulics influence the scaling tendency of minerals on the surfaces of completion tools in conventional resources. Although different studies have investigated the suitable conditions for the precipitation of scaling minerals, there is still a lack of understanding about the composition of the scaling materials deposited on the surfaces of completion tools in thermal wells. In this study, we presented a laboratory workflow combined with a predictive toolbox to evaluate the scaling tendency of minerals for different downhole conditions in thermal wells. First, the scaling indexes (SIs) of minerals are calculated for five water samples produced from thermal wells located in the Athabasca and Cold Lake areas in Canada using the Pitzer theory. Then, different characterization methods, including scanning electron microscopy (SEM) with energy dispersive X-ray spectrometry (EDS), inductively coupled plasma mass spectrometry (ICP-MS) and colorimetric and dry combustion analyses, have been applied to characterize the mineral composition of scale deposits collected from the surfaces of the completion tools. The results of the SI calculations showed that the scaling tendency of calcite/aragonite and Fe-based corrosion products is positive, suggesting that these minerals can likely deposit on the surfaces of completion tools. The characterization results confirmed the results of the Scaling Index calculations. The SEM/EDS and ICP-MS characterizations showed that carbonates, Mg-based silicates and Fe-based corrosion products are the main scaling components. The results of dry combustion analysis showed that the concentration of organic matter in the scale deposits is not negligible. The workflow presented in this study provides valuable insight to the industry to evaluate the possibility of scaling issues under different downhole conditions.

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.

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.

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.

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.

Previous studies showed that the fouling materials strongly affect the plugging of sand control devices during the oil production, thereby reducing oil productivity index drastically. In this study, we investigate how the compressive and tensile strengths of fouling materials affect the cleaning performance of shock waves generated by an electrohydraulic stimulation (EHS) tool. First, we synthetically plug wire-wrapped screens using different class G cement slurries widely used in oil fields. Silica, calcite, clay, and organic carbon powder as additives are mixed with the cement at different concentrations. Next, we evaluate the compressive and tensile strengths of the cured cement samples by performing uniaxial compressive strength (UCS) and Brazilian tests. Finally, the cleaning performance of the EHS tool is evaluated for plugged wire-wrapped screens. The UCS and Brazilian tests results show that the presence of additives changes the mechanical properties of cement samples. The compressive and tensile strengths of cement samples prepared with silica are found to be higher than those prepared with calcite and clay. Besides, the results of the pulsing stimulation treatment performed by the EHS tool show that the cleaning performance of the EHS tool for the wire-wrapped screens plugged with cement and carbon powder is the highest among all samples as cement samples with carbon powder represent the weakest mechanical properties (UCS and tensile strengths) among all samples. This study provides valuable insights into understanding the effect of shock waves on cleaning the plugged wire-wrapped screens. The results also enable production engineers to better plan for the treatment of damaged wells.

A central issue in hydraulic fracturing treatment in petroleum wells is the transport of proppant particles by the injection fluid. In this paper, we present an innovative proppant transport model in a fixed rectangular- and elliptic-shaped slots. The proposed model is an improvement to the current modeling of proppant transport by applying a non-oscillatory numerical scheme which has high accuracy everywhere in solution domain, even close to the steep gradients. In addition, inertia, fracture wall, and concentration effects on proppant settling along with slurry evolution as a function of proppant concentration has been considered. This paper introduces the mathematical equations that govern the proppant transport phenomenon and discusses special front capturing numerical techniques, boundary conditions, coupling between proppant and slurry mass conservation equations and time stepping restrictions required for the solution stability. We incorporated published correlations obtained from proppant transport laboratory experiments in our numerical model to better capture the physics of the problem. 5th- order WENO scheme was used to avoid oscillation and diffusion at the proppant front since traditional finite difference discretization was found to be insufficient in solving the hyperbolic transport partial differential equations. Results show that the technique used in this study can capture the proppant distribution with minimum oscillation and diffusion. A series of sensitivity analysis was conducted to explore the legitimacy of these assumptions and to provide guidelines that allow more accurate predictions of the proppant and fluid transfer. Numerical results are presented to show how proppant distribution is impacted by the injection fluid viscosity, density difference between proppant particles and injection fluid, proppant size, and fluid flow injection rate. Results of the sensitivity analysis illustrate the significance of choosing appropriate viscosity of the injection fluid as small changes in the viscosity may cause noticeable effects on the concentration distribution. In addition, we found that variation of proppant size and density within a reasonable range have a modest effect on proppant concentration distribution. Furthermore, we also investigated the amount of gravity driven vertical motion of proppant which is driven by density differences (convection) and compare it to a second gravity driven motion which is proppant settlement. Both of these two well recognized mechanisms can occur inside a fracture during proppant placement, however, the importance of each mechanism as a function of proppant injection design parameters is not fully understood.

The effects of Ca2+ on the CO2 corrosion behavior and film characteristics of N80 carbon steel and electroless Ni–P coating at high temperature and high pressure were investigated by immersion tests, in-situ electrochemical measurements, surface characterization techniques and water chemistry analysis. The results demonstrate that the corrosion of N80 steel is significantly influenced by Ca2+ concentration, however Ni–P coating exhibits exceptional corrosion resistance regardless of Ca2+ concentration. The microstructure and compactness of FeCO3 corrosion film is altered with the increased incorporation of Ca2+, thereby affecting the electrolyte penetration and the corrosion rate consequently. The added Ca2+ also impacts the water chemistry of the aqueous phase, postponing the FeCO3 precipitation. Meanwhile, the superb corrosion resistance of Ni–P coating is owing to the protection of the formed NiO/Ni(OH)2 film and the absence of scale formation.

In petroleum engineering, the transport phenomenon of proppants in a fracture caused by hydraulic fracturing is captured by hyperbolic partial differential equations (PDEs). The solution of this kind of PDEs may encounter smooth transitions, or there can be large gradients of the field variables. The numerical challenge posed in a shock situation is that high-order finite difference schemes lead to significant oscillations in the vicinity of shocks despite that such schemes result in higher accuracy in smooth regions. On the other hand, first-order methods provide monotonic solution convergences near the shocks, while giving poorer accuracy in the smooth regions. Accurate numerical simulation of such systems is a challenging task using conventional numerical methods. In this paper, we investigate several shock-capturing schemes. The competency of each scheme was tested against one-dimensional benchmark problems as well as published numerical experiments. The numerical results have shown good performance of high-resolution finite volume methods in capturing shocks by resolving discontinuities while maintaining accuracy in the smooth regions. These methods along with Godunov splitting are applied to model proppant transport in fractures. It is concluded that the proposed scheme produces non-oscillatory and accurate results in obtaining a solution for proppant transport problems.

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.

This study presents an investigation of the on-site corrosion of carbon steel pipes with stainless steel mesh screens in a steam flood well in the Athabasca oil sand reservoirs to determine the failure patterns and mechanisms. To mitigate the corrosion of carbon steel, several candidate materials were selected, and their corrosion resistance was investigated. In this work, the corrosion behavior and film characteristics of carbon steel pipes were studied by surface analysis techniques such as scanning electron microscopy, energy dispersive spetrocsopy and X-ray diffraction. Corrosion resistant alloys (proRSf and proRSc), anti-corrosion coating (proRA05a) and pre-treated steel (proRAQa) were considered as alternative materials to carbon steel (proRAa and proRAb) and their corrosion protection performance in brine solution was evaluated by electrochemical methods such as potentiodynamic sweep and electrochemical impedance spectroscopy. Results show that severe erosion-corrosion occurred on inner wall of the pipes and caused significant wall-thinning of pipes along with localized corrosion damages, which is the dominant reason for base pipe failure. In spite of the slight corrosion on outer wall of the base pipe, severe localized corrosion appeared at the interface between the carbon steel pipe and stainless steel mesh screens due to the galvanic corrosion effect of dissimilar metals. The corrosion rates of the corrosion-resistant materials were two or three orders of magnitude lower than that of carbon steel. The corrosion resistance ranking order is proRSc > proRSf > proRA05a > proRAQa > proRAa > proRAb. This study improves the material selection procedure in thermal operations by investigating several alternatives to carbon steel. It also provides a testing procedure to assess the corrosion resistance of the material in thermal applications.