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.

Reservoir simulation projects are ubiquitous across the oil and gas industry. A less common practice is retrospective validation of the accuracy and robustness of the original model's predictions. This paper highlights the importance of validating previous simulation work with field data in order to test predictability and acquire more confidence in future simulation work. A fully implicit coupled wellbore-reservoir simulator was used to history match the performance of four steam-assisted gravity drainage (SAGD) well pairs after one year of operation. The purpose of this effort was to build a representative model that mimicked the observed field behavior and captured the key performance drivers such as reservoir quality, completion type, and operating strategy. A representative history matched model was achieved with an overall accuracy within 9.5% of actuals after one year of operation. This model was used to forecast well pair performance after three years. After three years of field operation, the predicted simulation forecast was compared against the actual field data. The accuracy and robustness of model's predictions remained valid and improved to within 7.5% of actuals after three years of operation. For two out of the four well pairs, the observed trends between the actuals and the simulation appeared to deviate due to completion type and operating strategy changes that occurred after the original history match was completed. Once these changes were reflected in the simulation model, predictability was restored and improved reaching an accuracy within 4.7%. This paper aims to deliver two key learnings and best practices. First, a coupled wellbore-reservoir simulation approach was successfully applied to build a representative model that captures the key performance drivers and observed field behavior. Second, a retrospective validation of the model's predictions was completed and resulted in more accurate, robust, and confident performance predictions. These robust models can be used to better understand, forecast and optimize the productive potential of oil and gas operations over their life cycle.

Over the last decade, steam assisted gravity drainage (SAGD) process has been successfully commercialized in Alberta and Saskatchewan thermal projects. Remediation of slotted liner wells in cases of erosion, or high gas/steam production later in life requires a different basis of design based on specific well challenges and will be challenged by the additional pressure drops due to poor or variable sand control productivity. Flow Control Devices (FCDs) have demonstrated significant potential for improving recovery in SAGD production wells. FCD experience in SAGD has been primarily positive and most producers performed better with FCDs. While for some operators the results are mixed or negative. The first generation of FCDs deployed in SAGD projects were not designed for such process and in some cases ill-suited. Furthermore, current modeling methods deployed have significant limitations that prevent appropriate FCD design or understanding, and although they can be history matched, typically do not provide useful insight into the pressure drops encountered or held understand the benefit of different devices. In order to design and optimize FCDs for SAGD, it is necessary to characterize different FCDs under the steam-breakthrough condition, and accurately model the flashing in the near wellbore area associated with low-subcool operation. The extensive chocking in FCDs, far greater than initial design, in many cases is due to near-wellbore flashing. This work is a continuation of three previous parts discussing the liquid pool modeling for SAGD producers ( Irani, 2018 , 2019 and Irani and Gates, 2018 ). The purpose of this work is to create a PI that fit for purpose of SAGD liquid pool pre- and post-flashing that mainly can be used for analysis and optimization of FCDs. With FCDs, the draw-down pressure is typically higher, resulting in flashing near the well bore. If there is flashing in the near wellbore area, the temperature gradient within liquid pool yields the saturation curve. The flashing causes the reduction in the relative permeability of the liquid phase, that creates new equilibrium that stabilizes at lower rates. Such new equilibrium analysis is conducted by forcing a new temperature gradient to the model. The main output of such analysis is the produced steam quality at the producer sand-face. The steam quality is an important input for the flow control devices (FCDs) especially at subcool close to the zero, as it controls its behavior. This type of analysis can help the operators evaluate the effectiveness of different type of FCDs, whether they are primarily momentum- or friction-style devices.

In steam injection thermal recovery, it is essential to have a uniform flow to improve the recovery and to avoid the localized steam breakthrough which could lead to damage to well completion. In this paper, we propose three quantitative criteria to assess the performance of inflow control devices (ICD) based on computational fluid dynamics (CFD) modeling. The new performance criteria are exemplified in the evaluation of a few basic ICD designs. To evaluate the response of the ICD to flow rate and fluid type, three new performance criteria, defined as (1) quadratic flow coefficient, (2) viscosity coefficient, and (3) erosion potential, are proposed and evaluated based on a set of CFD simulations. The first criterion measures the flow rate response and the ability of the ICD to restrict high velocity flow, the second quantifies the viscosity sensitivity, and the third predicts the potential for erosion in the device. Four different liner deployed ICD designs, based on two passive design types (nozzle and channel) and one autonomous design type (Tesla flow diode), were analyzed using a rigorous CFD model. The model includes the surrounding slotted liner and inner tubing to identify any interactions of the ICD with the surrounding completion. The CFD model has been verified for grid and domain independence and it was applied to a range of flow rates representative of the field condition. In addition, simulations were run for a range of single-phase incompressible fluids with varying viscosities. Using the newly proposed criteria, the ICDs were evaluated and compared. The comparison shows that, of these devices, the diode does the best job of restricting the flow at high flow speeds and low viscosities. At high viscosities, such as in the case of oil, the diode is the least restrictive device. Although the two straight nozzles tested are slightly worse at restricting the flow, they have the lowest erosion potential. Based on this comparison and the proposed criteria, the channel design performs poorly. At low viscosities it does not sufficiently restrict the flow, and at high viscosities it overly restricts the production of oil. It also has a high erosion potential, because of the steep entrance angle. In this work, a new set of quantifiable criteria are defined and assessed that allow multiple aspects of different ICD designs to be compared simultaneously. Overall, these three criteria give a highly sensitive, quantitative means of comparing ICD designs. With these three criteria together, a more comprehensive comparison can be made in support of selection and improvement of ICDs.

Effective steam distribution in the injector is the key to achieve efficient and uniform reservoir heat up in SAGD operation. The focus of this research is on simulating the flow dynamics in outflow control device (OCD), the annular space between the liner and tubing, the slots, and the gap between the slotted liner and formation, using computational fluid dynamics (CFD). The objective is to use the approximated metamodel to optimize the OCD design and achieve more even steam distribution through the slots. A CFD model of the steam is developed through a systematic investigation of different domain sizes to study the effect of the pressure drop across the nozzle and the steam distribution. An evenness factor is proposed to quantify the overall steam distribution and to identify problematic slot areas. Based on the developed model, the OCD design is simplified and parameterized to conduct optimization efficiently. With the CFD expert system for steam simulation, the robust simulation models corresponding to different designs are obtained, providing accurate simulation results to the optimization algorithm. Using metamodeling, the response to the five design variables is derived, and the optimum is obtained subsequently. A cylindrical region representing the vicinity of the liner is added to the periphery of the slots to translate the optimization results into the realistic design. The CFD simulation and OCD design optimization show that the steam distribution is highly controlled by the OCD design, mainly by the nozzles’ distance to the central plane. The novel evenness factor provides a quantitative assessment of the effect of design changes and it enables the application of advanced design optimization algorithms. Fifty-five numerical experiments are conducted to obtain the relationship between the proposed evenness factor and the design variables. The overall design of the OCD can be fine-tuned to account for the steam distribution. At the beginning of the heating cycle, some flow reversal is found in some specific slots, which may lead to sand production, plugging and erosion. When the distance between the two sets of nozzles is extended to 50 mm, the normalized evenness factor shows that the steam distribution can be improved by 12.5% from the original design in which the distance used to be zero. Moreover, the velocity magnitudes in the reverse flow affected region are also reduced in the optimized design. The CFD simulation is a powerful tool to understand the flow dynamics through OCDs. This study applies a robust CFD model to investigate the complex flow interactions that affect steam distribution through OCDs to improve their design and thus to improve the steam distribution. The provided model and the design optimization algorithm could ultimately improve the heating efficiency.

Cyclic solvent injection (CSI) is a promising technology for enhanced production of heavy oil in post-CHOPS (Cold Heavy Oil Production with Sand) fields. The first stage of a CSI cycle involves the injection of solvent vapour, which re-energizes the reservoir and dissolves into oil, reducing its viscosity. The second stage of a CSI cycle involves dropping the pressure to flow the solvent-diluted oil back to the well. This is the solvent analog to cyclic steam stimulation (CSS). A key difference between solvent and steam is that the heat from steam stays in the oil even during production, while in solvent-diluted oil, if solvent comes out of solution as pressure drops, oil viscosity will increase again and one of the main benefits of the solvent will be lost. Solvent selection in CSI needs to consider which solvents have non-equilibrium properties, specifically delayed release during pressure depletion. This study presents a set of low field nuclear magnetic resonance (NMR) tests that were run on a 3,370 mPa·s viscosity heavy oil and several solvents: methane-propane and methane-CO 2 . NMR measures the relaxation rate of protons in the presence of magnetic fields. When fluid viscosity decreases, the fluid signal relaxes more slowly. A properly calibrated NMR model can be used to measure the viscosity of the liquid phase in a solvent-oil mixture as pressure drops and gas leaves solution. This approach does not require flow, and can also be used to measure the in-situ viscosity of oil in the sand. Tests were run using methane-CO 2 solvents with varying CO 2 concentration to study the impact of live oil viscosity on the rate of solvent release. For lower initial live oil viscosity, the solvent is able to more quickly leave solution from the oil. Additional tests run using a methane-propane solvent demonstrate the impact of varying solvent type for the same initial solution viscosity. Both CO 2 and propane show significant non-equilibrium solvent release during depletion. Measurements of non-equilibrium solvent release from oil are an important piece in the understanding and modeling of heavy oil CSI. Equilibrium PVT data shows how different solvents can affect heavy oil systems, but the non-equilibrium solvent release is crucial for these solvents to work as recovery agents in the field. The results presented in this study provide useful data for CO 2 and propane as potential CSI solvents, and help in the understanding of the role of viscosity vs. solvent type in the diluted oil response.

Injector wells in thermal field developments in Western Canada are usually completed by slotted liners. The purpose of liner installation is preventing sand production after a shut-in, keeping a stable wellbore, and providing an appropriate steam distribution. The objective of this paper is to quantify the role of slot width and slot density on the sanding performance of the liner in cycles of injection and shut-in in a SAGD injection well, through a series of laboratory sand control tests. A large-scale sand retention testing facility was developed and employed to conduct a series of tests on slotted liner coupons with different slot widths and densities. These tests were tailored to simulate steam injection and backflow during the shut-in. Three representative particle size distributions for the McMurray Formation were used in this study ranging from coarse to fine sand. The experimental set-up allows to measure the amount of produced sand. Since the produced sand in steam injection wells is not usually cleaned out, the acceptable threshold for sand production in the injector should be more conservative than the same for producer wells. Testing results indicate that the sand control performance of the liner is governed by the slot width and density, and formation particle size distribution. Results indicate a negligible amount of produced sand with gas backflow for a properly designed liner even at very high gas velocities. Historically, there has been little attention to the sand control design for injector wells. This work highlights the significance of slot density and slot width in the sand control performance for steam injection wells. The paper provides the basis for the proper design of an effective sand control in SAGD injectors.

This paper presents a critical review of current evaluation techniques for the selection and design of sand control devices (SCD) for Steam Assisted Gravity Drainage (SAGD) wells. With the industry moving towards exploiting more difficult reservoirs, there is a need to review the current testing methods and assess their adequacy for sand control evaluation for different operational and geological conditions. In addition to a critical review of existing sand control testing approaches for SAGD, the paper also discusses the testing parameters in previous studies to evaluate their representativeness of the field conditions in terms of interstitial seepage and viscous forces, and flow geometry. Moreover, the paper reviews the analysis and results of sand control testing in the literature and assesses the sand control design criteria in terms of the level of acceptable sand production and plugging. Furthermore, the review evaluates the suitability of the sample size, sand preparation techniques, representation of the SCD in the testing, and experimental procedures. The review shows variations in the existing sand control testing in SAGD, in terms of not only approach, sand control representation, and sample size, but also regarding operational test conditions, such as flow rates and pressures. Ideally, large-scale pre-packed tests that include the effects of temperature and radial flow geometry would more closely emulate the actual conditions of SAGD wells than most existing tests allow. High temperatures may affect sanding and plugging through changes in wettability, permeabilities, and mineral alterations. Further, the varying velocity profile in radial flow towards the SCD influences the fines migration pattern differently from the linear-flow conditions in the existing Sand Retention Tests (SRT). However, large-scale radial-flow tests are constrained by cost and complexity. Most SRT experiments have employed high flow rates, exceeding the equivalent field rates. Utilizing realistic rates for the tests and appropriately capturing the actual fluids ratios, water cuts and steam breakthrough scenarios can improve the quality of testing data. Accordingly, existing SRT experiments can be designed to incorporate, if not all, but some of the relevant physics in SAGD by employing representative viscosities, flow rates, fluid properties and ratios, stress conditions and obtain suitable live and post-mortem measurements. This critical review compiles various aspects of current sand retention tests and evaluates their applicability to SAGD well conditions. It serves as a starting point for future research by providing an overview of existing testing methods, highlighting the strengths and opportunities for improvements.

In Steam Assisted Gravity Drainage (SAGD) projects, it is essential to heat the reservoir evenly to minimize the potential for the localized steam breakthrough. Steam breakthrough can cause erosive damage to the sand control liner by the flow of high-velocity wet steam, and, in extreme cases, can compromise the mechanical integrity of the liner. This research investigates the sanding mechanism during the high-quality steam injection into the SAGD production wells. A large-scale Sand Retention Test (SRT) was used to investigate the role of steam breakthrough in the sand control performance. Produced sand and pressure drops along the sand-pack were the main measurements during the tests. The test procedure and test matrix were designed to enable the examination of the impact of steam breakthrough on sand production for different steam rates. Two possible sanding mechanisms are postulated in steam breakthrough events: (1) local grain disturbance caused by the high-velocity steam near the liner, (2) effect of the complex phase behavior of the steam and the subcool level. Two different testing procedures were designed to examine these mechanisms. The local grain disturbance mechanism was investigated by injecting air at a wide range of velocities. Results indicate that this mechanism could not lead to a significant sanding when there is a bit of effective stress near the liner. Hence, it looks like that the steam velocity poses a higher risk in early stages of SAGD production when the near-liner stress is very low. The effect of high-pressure high-temperature (HPHT), low- to high-quality steam flow and the subcool level will be investigated in the next phase of the study. This work addresses the effect of high-quality steam breakthrough on the sand control performance of the liner in SAGD producer wells. The findings in this paper help the researchers to direct their research to better understand the steam breakthrough. This research will eventually help the engineers in their liner design and evaluation for the entire wellbore life cycle as the near-well stress evolves.

Steam Assisted Gravity Drainage (SAGD) producer wells in the McMurray formation require sand control technologies that will limit sand production while minimizing production constraints caused by high pressure drops and liner plugging. Previous publications around sand control selection and sizing for SAGD producers have provided varied and often conflicting design recommendations based on the expected formation sand particle size distribution. Small scale lab testing of sand control medium is often challenged with inconsistent results and uncertainty around the appropriate normalization for test comparison and scaling up to real-world applications. Devon Canada designed and constructed an in-house large scale liner testing apparatus to evaluate sand control technologies and determine the optimal aperture or filter size for sand types expected in the McMurray formation of the future Pike 1 SAGD project. The large scale liner testing results are presented in this paper along with the final recommendation for sand control on Pike SAGD producer wells. A brief review of the Pike McMurray sand typing and small scale liner testing is also presented.

Field trials of tubing deployed Inflow Control Devices (ICDs) were conducted at the Grand Rapids SAGD Pilot from 2014 to 2016. The objective of the trials were to evaluate the flow performance of ICDs in a tubing deployed completion and assess improvements to thermal conformance. Key performance metrics were established to monitor changes in well performance, including production rates, thermal conformance, steam production and Steam to Oil Ratio (SOR). A comprehensive study was undertaken after the trials concluded. Multiple approachs were taken including analytical representations and simulations. The purpose of the study was to improve understanding of the underlying physics that govern flow and thermodynamic behavior of ICDs. The study specifically addressed restriction effects for various inflow conditions, steam flashing effects through the devices and heat exchange effects associated with the completion design. The results of the study identify some design principles that may be used for future application of ICDs in SAGD wells. Well Pairs 1 and 2 at the Grand Rapids Pilot project were used to test different ICD completions in a SAGD well pair. The Well Pair 1 field trial began first and lasted seven months. Learnings from the Well Pair 1 trial were extended to the Well Pair 2 trial which lasted 18 months. Flowing and shut-in temperature profiles were collected to understand near wellbore conditions and 4D seismic was used to ascertain changes to thermal conformance in the reservoir. Analytical and numerical models were developed to match field observations from the trial. Results from the field trial provided unique learnings with respect to the benefits that tubing deployed ICD systems may provide for SAGD wells. Changes in conformance and temperature distribution in the lateral sections were noted with little to no uplifts in oil rates or SOR. Once the trials were complete, all ICDs were removed from both well pairs and subject to visual inspections. Thereafter, a sample population of devices underwent a series of tests to evaluate mechanical integrity. The tests also characterized any changes to ICD flow relationships before and after the trial. Inspections of the devices post-operation provided crucial learnings on the mechanical integrity of such systems.

Over the past few years, an increasing number of operators in steam assisted gravity drainage (SAGD) in situ recovery of bitumen in the Alberta Oil Sands are becoming interested in the use of flow control devices (FCDs). Initial field trials by some operators of these devices have shown promise in improving steam chamber conformance, reducing incidences of steam breakthrough, high vapour production, and in addressing liner reliability concerns related to steam jetting. While the application of FCDs is well-established in the conventional oil and gas industry to control gas and water coning, there are still a number of questions on how to implement FCDs optimally in SAGD. One major difference in the application of FCDs in SAGD compared to the conventional oil and gas industry is the high temperature environment with steam and elevated erosion risk. The purpose of this paper is to present some practical considerations for the selection of FCDs and optimal completion FCD design for SAGD applications. In the first section, a discussion is presented on how to compare the performance of different flow control devices. Most devices have not been tested for SAGD, and there is a need for more comprehensive testing. The focus of the second section is on practical considerations for the installation of FCDs in a SAGD injection and production wells.

A pressure-gradient-based sand failure criterion has been proposed and validated to quantitatively determine the sand production and then characterize the corresponding wormhole growth and its propagations during cold heavy oil production with sand (CHOPS) processes. The new sand failure criterion was firstly developed at a pore-scale by analyzing the mechanical balance around a throat. To simplify the mechanical analysis, a pseudo-interaction force between a failed throat and the rest was proposed to comprehensively and implicitly represent the potential contribution of cementation and geomechanical stresses to fluidization of sand particles. As such, the mechanical balance was mathematically expressed by use of the pressure gradient, the pseudo-interaction force, and the friction caused by the mobilization of sand particles. Then, the sand failure criterion at the pore-scale was achieved and further extended to a grid-scale since the pressure gradient, a key factor dominating the sand production, is constant at either a pore-scale or a grid-scale within wormholes. With the bottomhole pressure as input constraints, the newly proposed sand failure criterion has been validated by history matching production profiles (i.e., cumulative oil production, cumulative gas production, and cumulative sand production) and wormhole propagations of laboratory sand production experiments in the literature. The new sand failure criterion has also been successfully applied to quantify the sand production and then characterize the wormhole propagations of a CHOPS well in the Cold Lake field, Canada. Good agreements have been found from history matching both the experimental measurements and field observations, confirming that the newly proposed sand failure criterion can be used to reproduce the multiphase flow under CHOPS conditions. It is found that both the sand failure and slurry flow contribute to the continuously observed sand production. According to the experimental measurements, the history-matched pressure distribution indicates that the wormhole propagation greatly depends on the magnitude of the breakdown pressure gradient. It is shown from the generated wormhole propagations that continuous sand production may cause heterogeneity no matter whether the original formation is homogeneous or heterogeneous. In addition, the newly proposed sand failure criterion is convenient to be incorporated with any numerical reservoir simulator and thus to be useful for field cases since only a few parameters are required to be inversely determined.

Extra-heavy oil (XHO) reservoirs in South America represent some of the largest hydrocarbon accumulations (> 500 billion barrels) in the world. Primary production using long horizontal wells is a commercially proven technology for XHO reservoirs. The expected ultimate recovery with primary production is generally limited to less than 12% of original-oil-in-place (OOIP) and thermal EOR is critical for increasing recovery to 30–60% OOIP. Economic and environmentally viable thermal development of these reservoirs will require the use of horizontal steam injectors. Our results reveal that a continuous steam injection with a horizontal injector placed vertically above a horizontal producer (CSI-HIHP) is a very effective method for XHO reservoirs, with high peak oil rate and significantly high recovery. This study, first of its kind for an XHO reservoir, outlines an integrated workflow to evaluate production potential of a large XHO green-field using primary production followed by thermal exploitation. The workflow, based on a probabilistic framework (involving designs of experiments, proxy methods and Monte Carlo simulations), evaluates reservoir performance for the whole lifecycle of the field under a range of uncertainties and quantifies the impact of key parameters affecting the reservoir performance. XHO reservoirs usually have significantly higher pressures than those of typical conventional heavy oil reservoirs, where continuous steam injection (CSI) has been applied commercially. Therefore, pressure in these reservoirs must be reduced before CSI can begin. Cyclic-steam-stimulation (CSS) after initial stage of primary production can be used to accelerate pressure reduction in the reservoir, while providing additional recovery. Our results demonstrate that geological features such as shale baffles have a significant impact on delaying pressure reduction during primary and CSS. In all the cases investigated, primary production for one year followed by CSS for four years has been found to be successful in reducing pressure to the target pressure for CSI. High pressure-drop in the horizontal steam injector can cause pressure near the toe region of the injector to be lower than the producer pressure. This results in poor steam injection and poor steam-chest development in that region, thus, greatly reducing efficiency of the thermal recovery process. We quantify pressure drop in a horizontal steam injector and its impact on the thermal performance and suggest a novel well configuration that uses two injectors for every long producer during CSI. The proposed configuration with a sequential development plan can significantly improve economics of the projects. A novel probabilistic workflow for a full-field development plan (primary, CSS and CSI) of XHO reservoirs provides robust production forecast over the entire lifecycle. The workflow developed and the insights obtained would be very valuable in preparing effective exploitation plans and optimal facility design, a key economic variable in large projects of developing giant XHO reservoirs.

This paper summarizes the results of reservoir simulations performed to investigate steam-air injection and its potential as a thermal recovery process. The steam-air injection process is considered to be any process that involves both steam and air injection whether they are injected together or at different times. The objective of the simulations was to develop steam-air injection based on its ability to divert steam from more to less oil depleted regions thereby improving reservoir contact (conformance) and increasing oil production. This diversion is caused by the deposition of coke and/or asphaltene in depleted regions or high permeability channels or thief zones. It primarily results from low temperature oxidation (LTO) of the oil. Air injection is most effective when used to divert injected steam when significant channeling/over-riding is occurring prior to air injection. Air should be injected at a relatively low rate and temperature in order that coke/asphaltene deposition occurs and facilitates steam diversion. Simulations showed that in a field application of the steam-air injection process, it is important to stop injecting air with/without steam once diversion has been obtained. Otherwise, oil will unnecessarily be consumed or degraded by LTO reactions and steam diversion may be reduced due to consumption of deposited coke/asphaltenes by high temperature oxidation (HTO) reactions. Continued injection of air could even increase channeling as it removes the coke and any residual oil by oxidation reactions thereby reducing the flow resistance in channels/thief zones. Air injection in a steam process is complex and it is not simply a case of injecting air with steam without careful consideration of the process.

In this paper, we present the results of an experimental investigation on the effect of pH and salinity on slotted liner performance in terms of sanding and retained permeability for heavy oil thermal production. This work is an advancement of the existing knowledge in the literature which indicates that pH and salinity could highly affect the mobilization, flocculation and deflocculating of clays (mainly Illite and Kaolinite) in oil sands formations. Water with different pH, in the range of 6.8 to 8.8, and salinities, in the range of 0 to 1.4 % was injected into sand pack samples supported with multi-slot coupon in a Sand Retention Testing (SRT) facility. Measurements included pressure drops along the sand pack and across the slotted liner coupon as well as the produced sand/fines for different flow rates. These measurements were used to assess the effect of the pH and salinity on fines migration within the sand pack, capability of the slotted liner to produce the fines, pore and slot plugging, sand production and the retained permeability. We observed that the pressure drops, fines production and the retained permeability are highly dependent on the pH and salinity of the injected fluid. In low pH and high salinity environment, clay is not mobilized resulting in low pressure drops and high retained permeabilities. On the other hand, an increase in pH value or a decrease in salinity leads to significant clay mobilization and a remarkable reduction in retained permeability. This paper provides a thorough experimental investigation of the pH and salinity effect on slotted liner performance. The effect of the pH and salinity is usually ignored in screen control testing while it could highly control the clay mobilization and retained permeability. Results of this study could trigger wide reconsideration in sand control approaches particularly by altering the pH in the near wellbore zone.

Alkaline-cosolvent-polymer (ACP) flooding of a heavy acidic oil (320 cp) was studied in a two-dimensional (2D) sand pack. An ACP formulation was developed by studying the phase behavior of the oil with several alkaline-cosolvent formulations. The effectiveness of the ACP formulation was validated in a 1D sand pack by conducting a waterflood followed by a stable ACP flood. Sand was then packed into a 2D square steel cell equivalent to a quarter five-spot pattern. Several ACP floods were then conducted in this 2D cell to study both the displacement and sweep efficiency of ACP floods. First, the polymer concentration in the ACP formulation was varied to find an optimum ACP slug viscosity where the oil recovery and pressure gradients are acceptable. When the ACP slug viscosity was about 1/4 of the oil viscosity, oil recovery was 76% OOIP; we adopted this viscosity as the optimum viscosity. Then, using this ACP slug viscosity, the waterflood extent, after which the ACP flood was initiated, was varied (0-1 pore volume). The oil recovery, oil cut, effluent concentration and pressure drop were monitored during the floods. The timing of the tertiary flood did not change the tertiary oil recovery very much. However, shorter the waterflood, faster was the oil recovery under the constant injection rate constraint. Sweep efficiency during secondary ACP flood was lower than that in the tertiary ACP injection. Gravity effect on sweep was significant under ultralow IFT.

An experimental study was conducted to investigate the relative permeability behaviour of a typical Canadian bitumen, water and gas. Series of isothermal core flood experiments were conducted on an unconsolidated core composed of cleaned Athabasca sand matrix and relative permeabilities of the involved phases were determined. Athabasca bitumen was used as the oil phase and distilled water and nitrogen were used as water phase and gas phase respectively. A vertical sand-pack core-holder of 1.5 inch diameter and 2 feet long was designed and fabricated to perform sequential injection of oil, gas and water at reservoir temperature and pressure, while collecting information on pressure drop across the core and fluid volumes. The history match technique was used to determine relative permeabilities for two-phase and three-phase water/oil/gas systems.

JACOS’ Hangingstone Demonstration Project has been in operation since 1999. The company has used the 10,000 bbl/D facility as a foundation for learning and refining SAGD processes and operations. The 24 operational well pairs, with 15 years of production has provided valuable insight into the performance of different liner completion types and operational control mechanisms. Data from the Demo project has provided the basis for a liner test strategy and liner design for application at JACOS’ Phase 1 Hangingstone Expansion project. First steam is expected in late 2016. All of the 24 operating well pairs at the Demo project have concentric tubular designs, but varying liner completion types. One well pair is completed with MeshRite TM , 13 well pairs with wire wrap screens and 10 well pairs are completed with slotted liners of varying slot sizes. With a relatively strong surveillance program, the flow distribution (inflow), subcool control, hydraulics and operability for each of the well pairs were carefully analyzed. The performance of wells with MeshRite, wire wrap screen and slotted liners will be presented. The analysis provided insight into what was successful in the field and provided a strong basis for the test design. As part of the expansion project, field performance data from the six phases of the Demo project, coupled with particle size analysis, flow testing and thermal performance analysis, guided JACOS to select slotted liners for all injector wells. For the producers, 27 wellbores were completed with wire wrap screens and five wellbores with MeshRite liners, for a total of 32 well pairs. This comprehensive study incorporated field learnings, operational successes, and a comparison between the flow test observations and field observations. Finite element analysis and specialized drilling mud contributed to liner installation success for the Hangingstone Expansion.

Heavy oil extraction is mostly based on thermal EOR processes. Warming up the reservoir reduces oil viscosity, makes it more mobile and in turn enhances heavy oil recovery. The most prominent thermal heavy oil EOR method relies on steam injection. This recovery process consumes high quantities of fresh water and energy to produce the steam, and heat loss due to reservoir heterogeneities and thief zones must be minimized. For that purpose, steam foams can be used to decrease steam mobility and improve its utilization by a better distribution in the reservoir. Selection of appropriate products for steam harsh temperature conditions poses several challenges regarding chemicals stability and foam durability. We have shown in previous papers that synergistic association of thermally stable surfactants can highly improve high temperature foaming performances. Here, we extend these results to specific surfactant formulations designed to provide enhanced bulk viscosity. These formulations are intended to compensate for the strong decrease of water viscosity with temperature. This is expected to enhance steam foams lifetime and in turn provide a better steam mobility control in application conditions. Bulk foam half-life is highly dependent on experimental conditions, in particular on the initial state of the foam in terms of quality and bubble size. This is even truer for steam foams that are also highly sensitive to possible temperature gradients. An optimized experimental setup has been developed to evaluate high temperature foam half-life obtained with standard and enhanced viscosity formulations. We couple these measurements with rheology and mobility reduction evaluation in sandpack experiments. Based on these various parameters, we try to extract correlations between bulk steam foam half-life, bulk viscosity and mobility reduction in porous media. This paper describes the characteristics of newly developed enhanced viscosity surfactant formulations, and also provides data regarding impact of viscosity on high temperature foam stability and mobility reduction.