In in-situ oil sands operations using Steam Assisted Gravity Drainage (SAGD), understanding the temperature and pressure responses during periods of shut-in and slow-down is crucial for effective steam chamber management. The corresponding operating strategy should be based on the temperature and pressure performance. At Nexen’s Long Lake in-situ project, there are a number of pads with extensive top water in contact with the target bitumen interval. Along with the rest of the wells in operation at Long Lake, these SAGD wells have experienced several periods of shut-in and slow-down due to maintenance operations and other surface constraints. Surface and downhole sensors and other real-time monitoring technologies provide opportunities to monitor temperature and pressure during these time periods, which help to better understand the impact of surface activities on steam chamber development, particularly in areas with extensive top water present. This paper presents the temperature and pressure responses over time at different elevations within the reservoir. It compares temperature and pressure responses for the wells with top water and without top water and 4D seismic is also integrated to analyze the causes for the different temperature and pressure responses. Review of the data shows that shut-in has a more significant impact on temperature and pressure in the steam chamber than slow-down. Wells with top water experience severe temperature drops while slow-down wells do not. After long periods of shut-in, areas with thicker top water may take additional time to heat up and reach steam conditions again, resulting in higher steam injection requirements. The collected data suggests that continuous steam injection is crucial to maintain steam chamber with top water.

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.

In steam assisted gravity drainage (SAGD) process, accumulation of non-condensable gases at the edges of the steam chamber creates a resistance to heat transfer between hot steam and cold bitumen, thus slowing down growth of the steam chamber. Efficient removal of these gases from the steam chamber can substantially accelerate the recovery process. Typical practice in SAGD is to use steam splitters and strive for a relatively uniform pressure in the horizontal part of the well, which allows for even distribution of injected steam into the reservoir. In convective SAGD process, a significant pressure gradient is deliberately created along the horizontal length of the injector well by tailoring the well completion design. Enhanced flow resistances can be fashioned by using finned tubes, static mixers, flow constrictions or simply using tube sections with varying diameters. A complementary placement of resistances in the producer well prevents short-circuiting of steam. Pressure gradients created in the injector well are translated on to the reservoir, thus allowing for a sweep of non-condensable gasses from the steam chamber. In reservoir simulation studies, a novel convective SAGD process has shown significant improvement in oil production, with 20% higher peak production rates as compared to traditional SAGD while facilitating removal of non-condensable gases in excess of 90% from the steam chamber over the life of the well. Since fluids in the reservoir can now also move along the length of the wells, convective SAGD demonstrates a distinct advantage over traditional SAGD in heterogeneous reservoirs as horizontal barriers to flow can now be overcome with time. Currently, a field pilot is being pursued at Foster Creek to test the validity of convective SAGD process.

Optimizing the efficiency of the waterflood displacement process in heavy oils is critical to reaching the oil recovery goals. However, in the process of finding an economic and stable throughput for the process, in some cases significant sand production and generation of wormholes have resulted in premature water breakthrough and channelling destroying volumetric efficiency. In order to understand such events, a simulation study using a coupled reservoir and geomechanical simulator was used to determine the physics controlling the initiation and propagation of dilated zones resulting from sand production giving the premature breakthrough. An attempt was made to identify the importance of well configuration and what operating constraints can be altered to reduce the risk of these breakthrough events. The complex physics of sand production during oil recovery requires it to be modeled as a coupled process: multiphase fluid flow causing transient pressure gradients and geomechanics to calculate the resultant stress variation, permeability enhancement and shear/tensile failure around the induced dilated zone and finally coupling failure criterion for the dilated zone propagation combining pressure gradient and effective stress. A force balance criterion calculates the threshold fluid pressure gradient for sand mobilization based on the effective confining stresses in each numerical element. The stress variation across the loosely supported sand body (damage zone) at the edge of a dilated zone is captured by an elasto-plastic constitutive model using a Mohr-Coulomb shear failure surface combined with softening of the Young's modulus. The application of the coupled simulator in modeling waterflooding reveals critical insights regarding the significance of different factors contributing to the sand production problem. Multiphase flow, over vs. under-injection, and inter-well pressure gradient effects are critical to controlling the sand production initiation and evolution. Gas liberation below bubble point pressure conditions causes excessive pressure gradient and increases the possibility of sand production. The oil/water relative permeability impact emerges if the mixture mobility at a certain fraction is lower than the end points. As dilated zone geometry appears to follow the weakest zones often associated with high permeable layers; it highlights the significance of the reservoir heterogeneity in contributing to the sand production problem. The results of the current study add understanding to the significance of different mechanisms contributing to sand production and may be used to help mitigate the premature breakthrough problem observed in many waterflooding operations.

In the water lubricated pipeline transportation of heavy oil and bitumen, a thin oil film typically coats the pipe wall, which is often referred to as ‘wall fouling'. A detailed study of the hydrodynamic effects of wall fouling is critical to the design and operation of oil/water pipelines, as the viscous layer can increase the pipeline pressure loss (and pumping power requirements) by 15 times or more. In this study a parametric investigation of the hydrodynamic effects caused by the wall coating of viscous oil was conducted. A custom-built rectangular flow cell was used as the principal apparatus. The controlled parameters include the thickness of the wall coating layer, oil viscosity and water flow rate. For each test condition, the pressure loss across the test section was measured and the hydrodynamic effect of the wall coating on the pressure loss was determined. A novel procedure using CFD simulations was developed to determine the hydrodynamic roughness. The procedure was also applied for a set of pipeloop test results published elsewhere. The effects of wall coating thickness and water flowrate on the hydrodynamic roughness were evaluated. The most significant outcome of this analysis is a new correlation for the hydrodynamic roughness produced by a wall-coating layer of viscous oil. The knowledge gained from the current research will be beneficial for designing, operating and troubleshooting pipeline systems in which a viscous wall coating is produced, including water lubricated bitumen transport in the oil sands industry, CHOPS and SAGD surface production/transport lines. The methodology can also be extended to the analysis of any unknown hydrodynamic roughness.

CHOPS (Cold Heavy Oil Production with Sand) is a primary production recovery method used in the Western Canadian Lloydminster heavy oil region which contains about 3 billion m 3 of heavy oil. It increases heavy oil production rates by creating high permeability channels in the reservoir through aggressively producing sand with the oil. As a result of CHOPS, 5 - 15% of the initial oil can be recovered. This paper summarizes CHOPS history matches that used the CMG STARS™ simulator and representative process mechanisms in simulating two Husky CHOPS wells, one well was later used as a Cyclic Solvent Injection (CSI) pilot well and the second well was a communicating offset well during CSI. The history matches were pre-processed for the post-CHOPS CSI field pilot. They were part of the $40 million JIVE Program and were in support of a CSIfield development in the Edam area. The history matches predicted the reservoir conditions (e.g. pressure, effective permeability, effective porosity, fluid saturations, and mole fraction profiles) at the end of CHOPS to set up the CSI initial reservoir conditions (i.e. the start of CSI). Oil, water and sand production were well matched for both of the wells during CHOPS. Foamy oil and sand transport mechanisms were represented in the simulations. The simulation results and the CHOPS model described below provided insight into CHOPS depletion mechanisms and post-CHOPS reservoir characteristics. At the end of CHOPS, the CSI well was pressure depleted with low liquid inflow. In the simulations, the wormholes were predicted to extend to about 151 m from the CSI well. Wormholes from the offset well reached a source of water and had continuous water inflow. It was predicted that the offset well wormholes penetrated about 220 m into the reservoir. Conclusions include: The AITF CHOPS model can capture field production mechanisms and reservoir behaviors. Continuing lower rate sand production and wormhole network growth is essential to obtain sustained higher oil production rates during CHOPS. As a result of greater reservoir contact, a thinner pay with longer wormholes can produce more oil than a thicker pay with shorter wormholes. Directly obtaining reservoir properties from the field LAS log data and use of the thin layers in the log file as simulation layers were important in catching fluid flow behaviors and obtaining satisfactory history matches for oil and water production. Good CHOPS history matches and reservoir charactisation are essential for field CSI pilot wells as they quantify the post-CHOPS reservoir conditions, the extension of wormhole networks, and the depletion regions. Consequently, they provide predictive value for developing CSI operation strategies for successful post-CHOPS CSI applications.

In a cyclic solvent injection (CSI) process, a solvent gas is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is decreased and increased cyclically. This causes a dynamically changing pressure gradient across the solvent–oil mixing zone, leading to a convective mixing of solvent and oil in addition to molecular diffusion. This study aims at modeling the effect of pressure gradient-induced convection on the solvent–oil mixing process in the transition zone. A diffusion–convection model is developed to simulate the dynamic solvent–oil mass transfer in the transition zone during the CSI process. This model consists of two sub-models: a pressure model and a solvent concentration model. The pressure model considers the effect of a practical viscosity profile and the concentration model considers the effect of a dynamic convective mass transfer velocity. These two models are coupled through the convection velocity and oil viscosity across the transition zone. The entire model is semi-analytically solved, in which a piecewise linear approximation scheme is applied for the variable convection velocity and viscosity in the transition zone. Results show that during the solvent injection period, convection can significantly enhance the mixing of solvent and heavy oil. Larger solvent injection rates can be more efficient for heavy oil–solvent mass transfer. In addition, it is found that considerable solvent remains in the oil zone at the end of the production period, and this part of solvent is difficult to retrieve within a short time period.

Controlling the steam channeling is a major challenge for increasing production in heavy oil reservoirs developed by steam injection. The conventional gel used in water flooding reservoirs always has poor heat resistance, so this paper proposed a novel high-temperature gel (HTG) blocking agent on the basis of a laboratory experimental study. The HTG consists of nonionic filler and unsaturated amide monomer with graft polymerization and crosslinking. The optimal gel system has a high gelling strength and controllable gelation time, which is achieved through incomplete orthogonal design method. Then the stability and plugging performance are studied through singular and parallel sand-pack experiments. The results indicate that the HTG has strong salt resistance and dilution resistance. In addition, the HTG can still maintain high strength at 200°C for 72hr. The singular sand-pack experiments suggest that the HTG has good injectability that ensures the on-site construction safety. Moreover, the HTG has a high breakthrough pressure gradient after gelling and could keep the plugging ratio above 99.8% after gel breakthrough when the subsequent injected volume reaches 10PV. The results obtained in parallel sand-pack experiments show that the HTG can effectively plugging the steam channeling after injecting into the high permeability sand-pack from the production end, and force the subsequent steam to enter the low permeability sand-pack. That raises the producing degree of the low permeability sand-pack. Finally, the difference between high and low permeability sand-pack liquid production is reduced by 99.098%, indicating that the producing profile is tremendously improved, and the oil recovery is enhanced by 41.34%. As a result, the novel HTG blocking agent can be used to control the steam channeling in heavy oil reservoir.

Highly permeable lean zones that halt the growth of steam chambers through lateral spreading significantly affect the performance of steam-assisted gravity drainage (SAGD). Nexen's Long Lake and Suncor's Firebag SAGD projects reported existence of intersecting lean zones that behave as thief zones, causing the operating pressure to be lower than the desirable value to reduce heat loss in the lean zones. Given a high steam-oil ratio, long and continuous lean zones located vertically above or near a wellbore pose a challenge. Log analyses and core experiments reveal that the distribution of lean zones is close to being periodic in the upper and middle parts of the McMurray Formation in Athabasca. A simulation model with periodic lean zones is established to analyze the effects of these lean zones on SAGD performance. We investigate the effects of vertical distribution, horizontal spacing and sizes, and spatial relationship with SAGD horizontal wells. We classify the locations of lean zones as above an injector (AI), between an injector and a producer (BIP), and below a producer (BP). For each location, we assign different spacing for neighboring lean zones of different sizes. A lean zone must reach a critical size before this area can act as a thief zone, which is most significant in AI and BIP situations. In general, BP cases are hardly influenced by lean zones. We further control the vertical distribution of these zones using a triangular periodic function that depends on layer depth and connate water saturation. Changing the period of the dominant function yields different kinds of lean zone distribution patterns; we run simulations for each pattern. Results show that lean zones with small periods have significant effects on SAGD performance. We vary the injection pressure to obtain the highest net present value (NPV) based on the fact that more steam is released through the lean zones at a higher pressure.

A tractable, predictive modeling approach for Cold Heavy Oil Production with Sand (CHOPS) remains a significant practical challenge. In CHOPS, instabilities of oil-sand interactions lead to formation of meso-scale structures, such as wormholes or other defects. The sand stress concentration around these structures often leads to sand failure, and production of sand in the process. The failure and motion of sand alter the permeability, and hence affect the oil production. Because these structures result from the instability of the oil-sand interactions, sizes, shapes and locations of these structures are unpredictable. One can only describe them using the statistical methods. Furthermore, in typical well-drainage scale or multi-well-scale numerical simulations these mesoscale structures are typically below the level of resolution and must be modeled as sub-grid-scale effects. Rigorous well-drainage-scale averaged governing equations can be easily derived, but closure models for the sand stress and sand production cannot be adequately developed without proper description of the sub-grid effects. The sub-grid momentum balance equation for sand demands that the divergence of the sand stress balances the gravity, pressure gradient and oil drag. Since gravity is a constant, and for a given mesoscale structure, the oil flow rate and hence the drag is determined by the imposed macroscopic pressure gradient, without information from sub-grid-scale pressure variation, we assert that the pressure gradient is the only independent variable affecting the stress and failure in sand. This leads to the proposition of closing the well-drainage-scale averaged governing equations in terms of the pressure gradient without explicitly involving the sand stress. Based on this proposition we derive a well-drainage-scale pressure diffusion equation without explicit representation of the sand stress. To develop the closure models, we can extract information from both explicit full-physics simulations of the sub-grid-scale effects with resolved sand stress and from pilot scale production data. Full physics simulations using the multiphase material point method are shown to adequately model lab-scale wormhole experiments. History matched simulations at the well-drainage scale are shown to track transients in pilot data and are a measure of the success of the modeling approach.

In this paper, the results of a multi-year research project to develop reliable engineering scale-up models of water-assisted pipeline transport of heavy oils and bitumen are described. Empirical correlations currently in use do not properly account for the effects of flow rate and pipe diameter on friction losses. They account not at all for effects of water cut, temperature, oil viscosity or sand concentration. Additionally, sand accumulation in operating pipelines is a concern because no accurate method of predicting the conditions under which sand can be transported is available. In water-assisted pipeline transport, water present in the production fluid can form a layer that separates the oil-rich core from the pipe wall, thereby drastically reducing the energy required to transport the mixture. Alternately, small amounts of water can be added to provide the lubricating effect. A multi-year project to explore water-assisted flow regimes was sponsored by Husky Energy, Nexen Inc., Shell Canada Energy and four other heavy oil and/or oil sands producers. An extensive experimental test program was carried out in SRC's 50, 100 and 260 mm (diameter) pipeline flow loops, using oil/water/sand mixtures containing heavy oil, bitumen or a viscous lube oil. Measurements collected during the tests included the frictional pressure drop, thickness of the oil wall fouling layer and solids concentration distribution. The friction loss model developed as part of this project assumes that the flow is only partially lubricated by the water layer so that oil-oil contact at the pipe wall becomes more important as the water cut, superficial mixture velocity and/or ratio of oil-to-water viscosity decreases. The sand transport criterion developed here compares the particle terminal settling velocity to the friction velocity of the turbulent water layer. The models developed here provide accurate predictions for the scale-up, design and operation of water-assisted pipeline flow technology, which has significant potential to reduce the costs and environmental impact associated with heavy oil pro- duction and transportation.

At the end of primary production in heavy oil reservoirs, significant volumes of continuous oil remain in place. As production rates decline this EOR target has tremendous value for heavy oil producers. Many of these reservoirs are poor candidates for thermal recovery. Furthermore in regional sands or post-CHOPS systems, it may not be easy to pressurize these reservoirs for solvent-based recovery. Chemical flooding has potential for EOR in these systems, because the injection of chemicals can lead to the buildup of pressure gradients between injectors and producers, at least at the laboratory scale. These pressure gradients evolve due to improved viscosity of polymer solutions, the formation of emulsions in surfactant or AS floods, or both. The objective of this work is to improve our understanding of the mechanisms by which heavy oils are produced through chemical flooding. Linear core floods were run on systems containing two heavy oils of variable viscosity: 500 mPa•s and 16,000 mPa•s. For the lower viscosity oil polymer floods and ASP floods are compared. These tests illustrate the impact of improving the injection fluid viscosity vs. the additional benefit from the addition of surfactant. It was observed that heavy oil is produced more efficiently from ASP flooding compared to polymer flooding alone. The residual oil saturations are lower in ASP floods, even with lower differential pressure across the core. For the higher viscosity oil some production was achieved through AS flooding alone, but the addition of polymer was important for improving recovery. Tests were also run on a parallel core system, containing cores of relatively high and low permeability. This was a representation of a post-CHOPS reservoir containing preferential flow channels due to the presence of wormholes. Both surfactant and ASP solutions only accessed the high permeability core, so oil was bypassed in the lower permeability sand even with the addition of chemicals to water. This result demonstrates that laboratory studies may be dramatically over- estimating the success of chemical flooding in heavy oil, and poses a challenge for successful implementation of chemical floods in heterogeneous post-CHOPS heavy oil fields.

The oil sands of Canada are a rich resource whose extraction faces many challenges. The most common processes for recovering in situ resources (i.e. too deep to mine) involve heating the reservoir to reduce the heavy oil or bitumen viscosity to allow it to flow to wellbores where it can be produced. This paper presents an alternate concept for recovery of these resources that does not require heat to mobilize the bitumen and that is especially well suited to reservoirs that are too thin or too geologically complex for economic thermal recovery. The process utilizes water injection to "condition" a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. Establishing a pressure gradient between a set of injector and producer wells allows the production of a bitumen-sand-water slurry as the pressure gradient established overcomes the friction holding the reservoir sand in place. This produced slurry is then processed at the surface to extract the bitumen and the cleaned tailings are re-injected back into the reservoir to aid in the sweep of the in situ sand, support the overburden, and dispose of the tails. We have developed a first principles numerical model of the process that fully accounts for fluid flow and sand flow under reservoir conditions to simulate and understand the process. We have also developed a large scale (2 meter diameter sand pack) laboratory system to demonstrate the technical feasibility of the process under reservoir conditions. The technology is still in the early stages of development, but the laboratory and numerical modeling efforts demonstrate promising technical potential of the process at a field-scale. The ability of the process to work in thinner and more geologically complex reservoirs than other in situ processes, and with lower CO 2 and surface footprints than thermal and mining processes, could make this an attractive alternative recovery process for shallow to intermediate depth, in situ bitumen resources.

New slug flow data and closure relationships for heavy oils have recently become available in the literature for both horizontal and vertical flow. This laboratory data allows the testing of current modeling technology to understand what modeling gaps must be addressed and where more data is needed. Comparisons of the data with typical one-dimensional slug flow models were performed at conditions where the liquid flow in the liquid slug is either laminar, transition or weakly turbulent flow. The closure relationships such as distribution parameter, drift velocity, and holdup in liquid slug are discussed along with the impact of these choices.