This paper proposes a new criterion to estimate the impact of lean zones on thermal or thermal-solvent processes, such as SAGD, SA-SAGD, or EBRT (Imperial Oil's "Enhanced Bitumen Recovery Technology"). The interface stability of the steam/solvent chamber in the lean zone is related to the competition of heat transfer in either conductive or convective forms. This competition is described by a non-dimensional number, the Rayleigh number in porous media, which can be calculated by the parameters of the lean zone thickness, water mobility, thermal diffusivity, and steam chamber temperature. When a system's Rayleigh number is larger than a critical value, the primary heat transfer mechanism in the lean zone will be convection, in which the interface becomes unstable and may cause significant loss of steam or solvent. Analytical solution to obtain the critical Rayleigh number was given in literature ( Philip, 1982 ). For long axis horizontal cross sections, the critical Rayleigh number is estimated between 0.1 and 1. A significant number of simulation cases have been analyzed in a sensitivity study with CMOST (Computer assisted Matching, Optimization, and Sensitivity analysis Tool, Computer Modeling Group) to validate the above hypothesis. Monte Carlo simulation results have shown a strong correlation between the solvent recovery and the product of water mobility and lean zone thickness. This product is the essential part of the formula of modified Rayleigh number. Further calculation indicated that the critical Rayleigh number for the simulation models is between 0.1 ∼ 1 for SA-SAGD or SAGD and about 0.17 ∼ 0.32 for EBRT. Both are within the range given by the analytical solution. The critical Rayleigh number is introduced to the lean zone analysis for the first time. This physics-based criterion is able to give an answer to the estimate of performance impact of the lean zone for thermal and thermal-solvent gravity drainage processes. The Monte Carlo simulation confirmed the consistency between the numerical studies and the analytical solution.

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.

Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. It is believed that the heavy oil resource volume is in the 50 to 70 billion bbl range which makes it a world class resource. This work briefly summarizes the reservoir properties of these formations and provides an overview of the primary CHOPS recovery mechanism which only recovers on average 8% of the original oil in place. Therefore, the target for Enhanced Oil Recovery (EOR) processes are substantial. For instance, if an additional 2% (25% of the primary) oil can be recovered, this means an additional 1 to 1.5 billion bbls of oil production which can sustain the oil industry for many years in this area providing jobs and contributing significantly to government royalties. A number of EOR processes are reviewed in this study from the conventional water flooding technologies to more state of the art processes such as Horizontal well Hot Oil Circulation. It is shown that part of the resource with viscosities less than 5,000 to 10,000 cp can be a target for water/polymer flooding. While steam injection in heavy oil reservoirs can be very successful, more than 95% of the resource in Lloydminster is less than 10 m thick and, thus, is not amenable to steam injection due to excessive heat losses to the surrounding formations. However, EOR processes involving mild heating or no heating can be feasible in these thinner formations. A number of mild heating technologies are discussed. Two of these technologies have been piloted in the field: Hot Water Vapour Process and Horizontal Well Hot Oil Circulation. Field results from these pilots are presented and discussed in this paper. It appears that these technologies can offer significant commercial potential in post-CHOPS reservoirs as well as in areas where CHOPS or horizontal primary production wells have not been successful.

Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. It is believed that the heavy oil resource volume is in the 50 to 70 billion bbl range which makes it a world class resource. This work briefly summarizes the reservoir properties of these formations and provides an overview of the primary CHOPS recovery mechanism which only recovers on average 8% of the original oil in place. Therefore, the target for Enhanced Oil Recovery (EOR) processes are substantial. For instance, if an additional 2% (25% of the primary) oil can be recovered, this means an additional 1 to 1.5 billion bbls of oil production which can sustain the oil industry for many years in this area providing jobs and contributing significantly to government royalties. A critical literature review of Cyclic Solvent Injection (CSI) as a post-CHOPS EOR technology is conducted. The key aspects of laboratory and theoretical studies of methane and propane mixtures, CO2 and propane mixtures and pure CO2 injection are summarized. A number of field pilots have been conducted using these solvents in post-CHOPS reservoirs in Lloydminster. Implementation of field pilots is presented and results are discussed using publicly available data. It is shown that while CSI technology is technically successful, economic feasibility is more elusive. However, it appears that CO2 injection is more likely to be economically successful. Furthermore, the economic attractiveness of Cyclic CO2 Injection increases in an environment where greenhouse gas emissions are taxed and credits for disposal are available.

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.

As steam-assisted gravity drainage (SAGD) producers continue to look for methods for enhancing oil recovery, understanding the dynamics at play in the evolution of the steam chambers becomes critical. Steam thief zones introduce operational risks affecting the economic recovery of the bitumen. Sensitive reservoirs need careful monitoring to avoid compromising cap rock integrity and to detect steam breakthrough. A need exists for real-time, spatially sensitive temperature monitoring in production, injection, and observation wells. Although such monitoring has been used in production and injection wells for decades, operators of SAGD observation wells (with typical two to six per pad) mostly used either piezometers for single-point pressure and temperature measurements and/or multiple-point thermocouple bundles. Distributed temperature sensing (DTS) application in these remote environments has been limited by availability of infrastructure with temperature-controlled environment and power supply in close proximity to the wellhead, which most DTS interrogation equipment requires. In this paper we introduce and demonstrate the installation of a new stand-alone, low-power DTS solution to address the specific needs of remote observation wells within a northern Alberta SAGD field. An acquisition system with extended working temperature range and small geometry form is installed within enclosures equipped with temperature-control devices and zonal certification. Downhole temperature data is transmitted continuously over a cellular network to a secure server with data-trending software for ease of viewing. The system was installed in February 2015 and the downhole temperature data accessible through web browser download during the field trial period.

Throughout the past five decades, the heavy oil industry has developed various in-situ techniques for oil recovery from the vast global heavy oil reserves. The diversity of these techniques goes hand in hand with the diversity of the world reserves in terms of viscosity, burial depth, and reservoir complexity. Reservoirs exist, however, wherein the currently available commercial methods might not be technically and economically feasible. In particular, reservoir quality and caprock integrity can impose significant limitations on the feasibility of conventional methods, such as steam assisted gravity drainage (SAGD). This paper summarizes the results of a series of field trials in weakly cemented formations based on the creation of highly conductive multiazimuth vertical planes (MAVP) in soft formations. These planes are mechanically initiated and hydraulically propagated and have typical dimensions of 0.03×5×30 m and can be used in a new steam injection design. The potential application of this technique to enhanced oil recovery is investigated using a thermal reservoir simulator. Reservoir simulations show promising results in terms of cumulative steam oil ratio (CSOR) and oil production rate. Stabilized production was observed immediately after the startup and CSOR dropped to under 3.0 m 3 /m 3 in less than two years. The overall performance is nearly comparable to that of conventional SAGD, while it outperforms SAGD in certain conditions, including low vertical permeability and in the presence of low permeable shale streaks. Simulation results show that the performance of MAVP is nearly unimpaired when planes’ projection is discontinuous in either vertical or horizontal directions. The results also showed that the presence of a confined top water zone does not have a detrimental impact on the performance of MAVP; however, penetration into the top water zone must be avoided to achieve the best results in terms of CSOR. While surface mining and variations of SAGD are respectively used for very shallow and relatively deep reservoirs, the new methodology is applicable to reservoirs in the depth range of 70 to 600 m, where weak caprock integrity can impose a significant challenge. In addition, complex reservoir features, such as the presence of low permeable shale layers or low vertical permeability, have minimal effect on the performance of this technique.

This paper presents a numerical assessment for the Maximum Operating Pressure (MOP) of a Steam Assisted Gravity Drainage (SAGD) project considering the effect of the Natural Fractures (NFs) and intrinsic anisotropy of the cap shale. Current numerical and heuristic assessments usually ignore the effect of the intrinsic and structural anisotropy of the cap shale in the caprock integrity studies. A coupled Hydro-Thermo-Mechanical (HTM) model was developed to assess the MOP. The coupled model employed a novel constitutive model which was developed to investigate the effect of NFs and intrinsic anisotropy in the cap shale. The coupled model was validated against surface heave measurements, and later utilized in a sensitivity study to assess the MOP for cases with different number of NF sets, fracture density and fracture dip angle. Results indicate that the MOP is highly sensitive to the fracture density and dip angle. According to the results, vertical fractures have minor effect on the MOP while oblique fractures with the dip angle between 25° to 65° significantly affect the MOP. Neglecting the NFs can lead to significant overestimation of the MOP. This highlights the necessity to include the NFs in the caprock integrity assessments. The numerical model presented in this paper considers the intrinsic anisotropy and the presence of NFs in the cap shale, while existing mathematical tools for caprock integrity studies have not incorporated the intrinsic and structural anisotropy. Ignoring the anisotropy in caprock can potentially cause a considerable overestimation of the MOP.

Steam-Assisted-Gravity-Drainage (SAGD) has been extensively applied in thermal recovery from oilsands reservoirs in the Athabasca region of Northern Alberta. As the steam chambers associated with SAGD well pairs become mature, a form of abandonment is often applied for pressure maintenance in the depleted zone. Quantification of potential surface subsidence associated with SAGD abandonment becomes critical especially when the mature wells are in proximity of future developments. In addition, induced shear stresses should also be estimated to fulfill well integrity requirements. In this case study, a coupled reservoir – geomechanical simulation model is developed, calibrated and utilized to estimate the magnitude of post-abandonment subsidence and the induced shear stresses in Surmont SAGD Pilot Project. In the context of this study, first, the development of a simplified 2D static geomechanical model using an original geomodel realization as well as geomechanical properties and stress profiles is discussed, which forms the basis for the coupled simulation model. The calibration workflow of the coupled reservoir-geomechanical simulation model to historical heave data is then reviewed and the impacts of different parameters on calibration quality is investigated. Finally, the estimation of subsidence and the induced shear stresses in the nearby wells is discussed, and the magnitude of residual heave is quantified. The results of this study show that only a fraction (up to 40%) of surface heave is reversible (in form of subsidence) during the abandonment phase. Therefore, the magnitude of the surface subsidence and the associated shear stresses are quite small. The modeling study has also shown that a small magnitude of subsidence may be recorded even 10 years after abandonment. However, more than 50% of the surface subsidence is observed in the first two years post-abandonment. Other important findings of this study includes (1) documenting the effects of thief zone interaction as it relates to irreversibility of surface heave; (2) documenting the impacts of various geomechanical parameters on the quality of calibration against the historical heave data; (3) observation of the relative impacts of the pressure and temperature fields on the magnitude of heave; and (4) quantification of incremental, yet small, shear stresses along the nearby horizontal wells.

An approach based on artificial intelligence (AI) tools is being used to explore the influence of shale heterogeneities on SAGD production. In this project, the production data is derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs. The underlying reservoir simulation model is homogeneous, and two-dimensional. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. Superimposed on this homogeneous reservoir model are sets of idealized shale barrier configurations. The permeability of each shale barrier is several orders of magnitude smaller than the permeability of the oil sand in the simulation model. The individual shale barriers are categorized by their location relative to the SAGD well pair (vertical and lateral), and by their geometry (thickness and lateral extent). SAGD production was simulated with the reservoir model for a training set of shale barrier configurations. The training set was chosen to try to span the space of possible shale barrier configurations in the reservoir model; the elements of the set were identified by means of experimental design. A network model based on AI tools was constructed to match the output of the reservoir simulation model for this training set of shale barrier configurations, with a focus on the production rate and the steam-oil ratio (SOR). Then the trained AI proxy model was used to predict SAGD production profiles for scenarios where the shale barriers were distributed stochastically. The results of these predictions were compared with the results of the SAGD simulation model with the same shale barrier configurations. The match to production rate and SOR was good, better than expected. The results of this work demonstrate the capability and flexibility of the AI-based network model, and of the parameterization technique for representing the characteristics of the shale barriers, in capturing the effects of complex heterogeneities on SAGD production. The approach could be extended to study the effects of other heterogeneous features such as lean zones on SAGD production. It offers the significant potential of providing an indirect method for inferring the presence and distribution of heterogeneous reservoir features from the profiles of SAGD field production data.

Steam-solvent coinjection has been studied and pilot-tested as a potential method to improve steam-assisted gravity drainage (SAGD) for bitumen recovery. Reliable design of coinjection requires reliable PVT data for bitumen/solvent/water mixtures, which are scarce and fragmentary in the literature. The main objective of this research was to present a new set of PVT and multiphase data for n-butane/Athabasca-bitumen/water mixtures at pressures up to 10 MPa and temperatures up to 160°C. Experiments were conducted by use of a conventional PVT apparatus. The data presented include multiphase equilibria up to four coexisting phases and liquid densities for 100% bitumen, two mixtures of n-butane/bitumen, and one mixture of n-butane/bitumen/water. A single equation-of-state model was developed to correlate all experimental data obtained, and used to interpret complex multiphase behavior observed for the highly size-asymmetric polar mixtures. Liquid-liquid separation of hydrocarbons was experimentally observed at the n-butane concentration of 97 mol% in the n-butane/bitumen system with/without water, for a wide range of temperatures at operating pressures for expanding-solvent-SAGD (ES-SAGD). This may indicate the limited solubility of n-butane in bitumen even when a high level of accumulation of n-butane takes place near a chamber edge in ES-SAGD for Athabasca bitumen. The multiphase transition that involves appearance/disappearance of the vapor phase was observed to occur near the vapor pressure of n-butane or its extension. Such phase transition occurs at a higher pressure in the presence of water, due to its vapor pressure, than in the absence of water at a given temperature. This is the first time four coexisting phases are reported for n-butane/Athabasca-bitumen/water mixtures at temperature-pressure conditions relevant to ES-SAGD.

Steam assisted gravity drainage (SAGD) is a widely used thermal recovery method. During steam injection in interbedded sands, the portion of the deposits above the vertical permeability barriers is likely not recoverable with current practices. This paper discusses some of the geomechanics and fracturing aspects of using multistage fracturing in SAGD operations in interbedded sands such as IHS, where the vertical permeability barriers impede the gravity drainage process. The first part of this work (to be presented in a separate manuscript) covered the reservoir engineering aspects of this method, where it was assumed that it is possible to successfully create vertical fractures in the oil sands and through shale layers. In this paper, the geomechanical challenges in implementing the method and after the start of operation are discussed, starting with a review of relevant hydraulic fracturing field trials in the oil sands. Some interface crossing criteria are reviewed and the extended Renshaw and Pollard criterion is used to study fracture propagation through sand-shale interfaces. These results are then compared to results of a numerical simulation using a coupled reservoir-geomechanics-fracturing simulation software. It is shown that tensile hydraulic fractures can be created in the oil sands, and fractures can cross sand-shale interfaces and be filled with desired concentration of proppant. It is shown that small but high conductivity fractures that are required for the success of the proposed method, can be generated by using currently available proppants and fluid systems. After start of the steam injection, the conductivity of the fracture might be reduced by various mechanisms such as proppant embedment. It is shown that the reduction due to embedment would not be significant at high range of proppant concentrations and also due to the low stress regime in the Alberta oil sands. Furthermore, the design considerations for various liner systems that can combine the fracturing process and the SAGD phase are discussed and a few new designs are proposed. Finally, a step by step roadmap for field implementation of this method is presented. The novelty and main contribution of this paper is the analysis and design considerations of the application of multistage fracturing in SAGD process in the field. Our results indicate that the field execution is feasible, and a field trial of the technique is justified.

It is generally accepted that solvent-steam injection in heavy oil/bitumen reservoirs outperforms steam only injection in terms of oil recovery rate, ultimate oil recovery and steam oil ratio. Important parameters in SA-SAGD design are solvent selection, injection strategy and solvent retention in situ. The role of geomechanics in optimum application of SA-SAGD, however, remains largely unexplored. Recent studies suggest that solvent transport, solvent dilution effect and the temperature distribution around the edge of the steam chamber have major control over SA-SAGD performance. Solvent-steam injection significantly alters the temperature distribution around the chamber edge compared to steam only processes (SAGD). The temperature redistribution, in addition to the altered pore pressure, produces geomechanical effects such as porosity and permeability alteration, relative permeability changes and residual saturation alterations which in turn, influence solvent-steam-oil phase behavior and solvent transport and retention, among others. These chains of events affect the steam chamber growth and the solvent distribution, which affect optimum solvent selection and solvent-steam injection scenarios. These geomechanical considerations are of particular interest for bitumen deposits, both oil sands and carbonates, where chemical, thermal and fluid pressures can impose significant volume changes within the reservoir especially in shallower, lower confining stress settings. The role of geomechanics in SA-SAGD was explored numerically using a sequentially coupled modeling approach with STARS (CMG) and FLAC (Itasca). A 2D homogenous oil sands reservoir geomodel at a shallow depth was considered for the purpose of this paper. Studies were conducted at two scales: 1) edge of steam chamber and 2) reservoir scale including underburden and overburden. The results of these numerical studies revealed geomechanics considerations directly affect the optimum solvent type selection and injection strategy during high pressure SA-SAGD processes. These studies provide valuable direction for further detailed mechanistic studies (both numerically and experimentally) and provide valuable input to the challenges of optimizing SA-SAGD processes in oil sands.

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.

Although convective heat flux is neglected in classic steam-assisted gravity-drainage (SAGD) models such as the one derived by Butler, heat convection through the condensate flow into porous media can be very important. A key control on the condensate flow is the in-situ relative-permeability to water within the reservoir. To date there is no methodology that can calculate the in-situ relative-permeability to water in SAGD reservoirs during steam injection and progression of the steam chamber. The in-situ relative-permeability to water during steam injection can be different from laboratory and well-test results. The problem with the results from lab test is that they are mostly from disturbed cores or remolded samples. And the issue with results from both lab and well testing is that at the edge of the steam chamber, bitumen undergoes thermal expansion of some 15%; therefore, unless the water saturation increases by a similar amount, water mobility is quickly decreased by the expanding bitumen phase. A method is provided to calculate in-situ relative-permeability in oil sand reservoirs using the distance between pressure and temperature response at the same depth. The implementation of the concepts is tested for Underground Test Facility (UTF) project. The results suggest that the in-situ relative-permeability to water during steam in most SAGD projects is limited to 10 -4 to 10 -5 and having higher relative permeabilities is only possible at lean zones. This paper describes a new method for reservoir characterization based on water mobility for different oil sand projects.

Cyclic Steam Stimulation (CSS) can significantly change the volume of the bitumen-bearing reservoir. Uneven uplift of overburden caused by such volume change induces noticeable stress perturbation in the structure providing containment for the steam/bitumen emulsion and may lead to material yielding in subsurface structure. To study the impact and mechanism of such a phenomenon, InSAR images of surface deformation were collected between 2010 and 2011 at a CSS operation site. These interferograms were processed to 14 snapshots of surface deformation within that period of time. We observed that heave and subsidence can occur simultaneously across one operation site, as the heated steam front moves through the reservoir. A brief review of the production history of the site indicates that the surface deformation is directly related to fluid injection and extraction. In the first step of our modelling, we invert the surface deformation to assess the extent of reservoir expansion/compaction and induced subsurface deformation. Due to the highly non-uniqueness nature of the inversion results, we carefully benchmarked the mathematical and geomechanical parameters used in the inversion process. The results from the selected inversion parameters are compared with forward modeling results to increase the confidence of the inversion scheme. Subsurface deformation is modelled sequentially through Finite Element forward modelling. The computed reservoir deformation is channeled into the commercial FEM simulation software Abaqus to assess the stress and strain of the overburden. We load the deformation computed from inversion at the reservoir/overburden interface and then simulate the corresponding stress and strain alteration of the overburden. Simulation results show that uneven uplift from reservoir expansion and compaction can alter the stress state of the overburden significantly. This study shows that with proper knowledge of in-situ geomechanical characteristics, InSAR coupled with geomechanical modelling can be a useful tool to understand injection/production monitoring data and identify possible effects of CSS operations on the structural integrity of subsurface.

This paper presents a case study of the application of an Interferometric Synthetic Aperture Radar (InSAR) natural reflector (NR) survey to monitor surface heave and steam chamber growth at one of Suncor's steam assisted gravity drainage (SAGD) fields. InSAR is a satellite technology mainly used to monitor ground motion. An InSAR NR survey relies on back scattered signal from the ground surface itself as opposed to fixed corner reflectors (CRs) which are metallic trihedrals specially designed to reflect a radar signal. This allows a NR survey to cover large areas of ground compared to those carried out using corner reflectors, but at a lower accuracy. As such, InSAR NR surveys provide a potential way of monitoring surface heave that covers much of a SAGD field at very low cost. Results from the NR survey are very promising. First, the trends in the surface heave measured by the NR survey were almost as accurate as those measured by the CRs. In addition, the NR survey provided useful data over about 50% of the target area. This dense coverage was unexpected since the test site is covered by small trees and extensive areas of muskeg, which will interfere with the reflected radar signal. Reliable surface heave estimates could be made in topographically high areas and in areas with gentle slopes because of their drier nature. By contrast low lying areas that were generally wetter provided little to no reliable data, hence masking any surface heave. Benchmarking of InSAR NR data to temperature fall offs found that the NR measured heave compared well to steam chamber conformance on overall average trends. In addition, manually measured heave also compared well to steam chamber growth measured by 4-D seismic. In conclusion, results indicate that an InSAR NR surface heave survey provides a promising way of measuring surface heave and steam chamber growth over large areas of SAGD fields. It is complementary to 4-D seismic, but at as little as one hundredth of its cost. One of the limitations of a NR survey is that measurements must be taken in non-snow time. Areas of denser forest cover may not provide as much spatial coverage with NRs as was found at the target region discussed in this paper. InSAR coverage in these areas could be done using CRs.

The SAGD process can be achieved only after the thermal and hydraulic communication between the injection well and the production well has been established during the start-up operation. The start-up operation involves interactions of geomechanical responses and multiple phase flow behaviors in the inter-well formation. Such interaction would have an impact on SAGD in terms of recovery performance. This paper presents an experimental study on investigating the mechanisms and mechanics of geomechanical dilation and fundamentals during cold-water injection. A triaxial experimental program has been designed and conducted to verify geomechanical dilation through experimental measurements. A series of reconstituted water-wet/bitumen sand specimens were prepared with different fluid saturation and almost identical void ratio. Reclaimed/cleaned tailings sand from oil sands mining operations was used to prepare artificial specimens, which are representative of McMurray Formation oil sands. A water-wet or bitumen sand core plug was then tested in an environmental chamber to simulate reservoir boundary conditions in terms of stress state, temperature, and pore pressure. A series of experiments were carried out in a triaxial cell under either initial isotropic or initial anisotropic stress state. Experimental results highlight the promising potential to dramatically enhance effective permeability to water and porosity in the dilated zone with pore pressure injection at modest levels of stress anisotropy. The lab-scale experimental data provides supports on development of numerical models for predicting SAGD start-up performance and on proactive utilization of the dilation as start-up process for in-situ oil sands development.