Summary The Pelican Lake heavy-oil field in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production by use of vertical wells was poor because of the thin (less than 5 m) reservoir formation and high oil viscosity (800–80,000-plus cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. However, with primary recovery at less than 10% and 6.4 billion bbl of oil in place (OIP), the prize for enhanced oil recovery (EOR) is large. Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake because of the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first—unsuccessful—pilot was implemented in 1997, but the lessons drawn from that failure were learned and a second pilot was met with success in 2006. The response to polymer injection in this pilot was excellent, with oil rate increasing from 43 BOPD to more than 700 BOPD and remaining high for more than 6 years; the water cut has generally remained at less than 60%. Incremental recovery over primary production is variable but can reach as high as 25% of oil originally in place (OOIP) in places. This paper presents the history of the field and then focuses on the polymer-flooding aspects. It describes the preparation and results of the two polymer-flood pilots, as well as the extension of the flood to the rest of the field (currently in progress). Polymer flooding has generally been applied in light- or medium-gravity oil, and even currently, standard industry-screening criteria limit its use to viscosities up to 150 cp only. Pelican Lake is the first successful application of polymer flooding in much-higher-viscosity oil (more than 1,200 cp), and as such, it opens a new avenue for the development of heavy-oil resources that are not accessible by thermal methods.

Abstract A successful polymer flood is being implemented in the Pelican Lake heavy oil field located in Northern Alberta (Canada). With primary recovery around 5-7 % and several billion barrels OOIP, the field offered a big target for EOR but polymer flooding had never been considered in such high viscosity oil (600 to 80,000cp) until the idea of using horizontal wells gave way to a very successful 5 horizontal wells polymer flood pilot in 2005, followed by a progressive extension to the rest of the field. This paper provides a brief description of the polymer flood pilot then focuses on the various steps involved to generate a realistic reservoir model to history match the pilot. Polymer flooding in heavy oil reservoirs (1500 cp oil in the pilot area) using horizontal wells is really new and the response of the pilot was not totally expected. The oil rate has increased beyond expectations but more surprisingly, the water-cut has increased very slowly and is only in the 50-60 % range after 7 years of operations. History matching the pilot history was important in order to understand what was really taking place in the reservoir; it was performed using up to date Assisted History Matching techniques. Good results have been obtained in terms of history matching. The model can therefore be used to investigate the influence on oil recovery of many parameters such as well length and spacing, injection rate, polymer concentration, slug size, and to evaluate additional recovery compared to continued primary recovery or waterflood. History matching the pilot performance opens the door to a better understanding of polymer flooding in heavy oil reservoirs and to increasing the number of potential application cases.

Abstract In 2005, a polymer flood was implemented at pilot scale in the six billion barrels OOIP, 800 to 80,000cp oil viscosity, Pelican Lake heavy oil field (Northern Alberta - Canada), to evaluate the potential of polymer to significantly increase the primary recovery limited to 5–7% OOIP. The pilot comprising 5 parallel horizontal wells (2 injectors and 3 producers) is still continuing in 2013 with excellent results (oil rate increase beyond expectations and surprisingly very slow water-cut increase in the 50–60% range) that have led the operator to extend polymer injection to field scale. Understanding the wells responses to polymer flood, not totally expected in such a high viscosity oil, and optimizing the process have been undertaken through the following steps: 1) generation of a simplified reservoir model, consistent with geological trends and calibrated with core data, 2) automatic history matching of the pilot using dedicated tools, 3) investigation of sensitive parameters on oil recovery (well spacing, well length, polymer concentration, slug size, oil viscosity etc.), 4) range definition of optimum sensitive parameters both technically and economically. Successful history matching of the pilot gives some insights on the main influence of reservoir heterogeneities on oil recovery. The history matched reservoir model has allowed to investigate the influence of various parameters for the implementation of polymer flood in heavy oil fields, and evaluate additional recovery compared to continued primary recovery or waterflood. It also provides some guidelines on the applicability of the process to other reservoirs. History matching the pilot performance opens the door to a better understanding of polymer flooding in heavy oil reservoirs such as Pelican Lake and to increasing the number of potential application of polymer flood to similar fields.

The objective of this study is to evaluate which production information can be deduced from a 4D seismic survey during the Steam-Assisted Gravity Drainage (SAGD) recovery process. Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, in fluid saturations, in pore pressure and so on. This study is based on the real Hangingstone field case of the McMurray formation in the Athabasca region (Canada). In previous works, an initial static model (geology, petroacoustic and geomechanical) has been constructed and a thermal production of heavy oil with two coupled fluid-flow and geomechanical models has been simulated. Seismic parameters (density, compression velocity and shear velocity) of the saturated rocks have then been computed from mechanical and reservoir parameters at several stages of the production. A repeated acquisition survey is modelled at different stages of SAGD production. This is performed using a 3D seismic modelling approach. To focus on the reflections generated within the reservoir zone, a target-oriented modelling is chosen. It is based on the ray+Born approach which permits to compute the P-wave elastic response by correctly handling the seismic amplitudes as a function of source-receiver offset. Real incoherent noise is added to the zero-phase synthetic data to produce a more realistic result. The noise-free and the noisy synthetic data are processed to get stacked and time migrated images. A simple processing workflow leads to image the steam chamber development, in particular its V-shape in radial section, and to observe time-lapse in the reservoir zone. An interpretation work is then carried out. Some seismic attributes like RMS values of amplitude changes between stages, energy, time differences of reservoir bottom between stages, etc. are computed from the synthetic (noise-free and noisy) seismic data. Some of these attributes prove to be robust to the noise and to show some production effect. Possible trends between these attributes and the modelled reservoir/geomechanical properties (lithofacies, pressure, temperature, steam saturation, etc.) are also evaluated. Finally, geobodies are extracted from the seismic attributes.

The objective of this study is to evaluate which production information can be deduced from a 4D seismic survey during the Steam-Assisted Gravity Drainage (SAGD) recovery process. Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, in fluid saturations, in pore pressure and so on. This study is based on the real Hangingstone field case of the McMurray formation in the Athabasca region (Canada). In previous works, an initial static model (geology, petroacoustic and geomechanical) has been constructed and a thermal production of heavy oil with two coupled fluid-flow and geomechanical models has been simulated. Seismic parameters (density, compression velocity and shear velocity) of the saturated rocks have then been computed from mechanical and reservoir parameters at several stages of the production. A repeated acquisition survey is modelled at different stages of SAGD production. This is performed using a 3D seismic modelling approach. To focus on the reflections generated within the reservoir zone, a target-oriented modelling is chosen. It is based on the ray+Born approach which permits to compute the P-wave elastic response by correctly handling the seismic amplitudes as a function of source-receiver offset. Real incoherent noise is added to the zero-phase synthetic data to produce a more realistic result. The noise-free and the noisy synthetic data are processed to get stacked and time migrated images. A simple processing workflow leads to image the steam chamber development, in particular its V-shape in radial section, and to observe time-lapse in the reservoir zone. An interpretation work is then carried out. Some seismic attributes like RMS values of amplitude changes between stages, energy, time differences of reservoir bottom between stages, etc. are computed from the synthetic (noise-free and noisy) seismic data. Some of these attributes prove to be robust to the noise and to show some production effect. Possible trends between these attributes and the modelled reservoir/geomechanical properties (lithofacies, pressure, temperature, steam saturation, etc.) are also evaluated. Finally, geobodies are extracted from the seismic attributes. L’objectif de cette étude est d’évaluer quelle information de production peut être déduite d’une campagne sismique 4D durant le procédé de récupération par injection de vapeur SAGD (Steam- Assisted Gravity Drainage). En plus des hétérogénéités réservoir d’origine géologique, de nombreux facteurs interagissent pendant la production thermique d’huile lourde et de bitume, ce qui complique l’interprétation des données sismiques 4D : variation de la viscosité de l’huile, des saturations en fluide, de la pression de pore, etc. Cette étude est basée sur le champ pétrolier Hangingstone de la formation McMurray en Athabasca (Canada). Dans des travaux antérieurs, un modèle statique initial (géologique, pétroacoustique et géomécanique) avait été construit. Puis la production thermique d’huile lourde avait été simulée en mettant en oeuvre le couplage d’un modèle d’écoulement de réservoir et d’un modèle géomécanique. Les paramètres sismiques des roches saturées (densité, vitesses de compression et de cisaillement) avaient alors été calculés à plusieurs étapes de la production à partir des paramètres mécaniques et de réservoir. À partir de ces résultats, une acquisition sismique est simulée à quatre états de production SAGD. Comme on s’intéresse aux réflexions sismiques en ondes de compression générées dans le réservoir, une modélisation sismique orientée cible est choisie. Cette modélisation est basée sur une approche ray+Born et permet de calculer la réponse sismique en estimant correctement les amplitudes sismiques en fonction de l’offset (distance source-récepteur). Pour obtenir des données plus réalistes, du bruit réel incohérent est ajouté aux données sismiques synthétiques. Les jeux de données synthétiques non bruitées et bruitées sont ensuite traités afin d’obtenir des images sismiques temps sommées et migrées. Une séquence simple de traitement sismique permet d’imager le développement de la chambre de vapeur, en particulier sa forme en V dans le plan perpendiculaire aux drains horizontaux, et d’observer des différences de temps de trajet dans la zone réservoir. Un travail d’interprétation est alors mené sur ces données sismiques synthétiques à différents états de production. Plusieurs attributs sismiques, comme les valeurs RMS des variations d’amplitude entre états, les variations de temps de trajet à la base du réservoir entre états, ou l’énergie des images sismiques à chaque état, sont calculés sur les données synthétiques non bruitées et bruitées. Quelques attributs sismiques apparaissent robustes au bruit et impactés par la production. Les relations entre ces attributs sismiques et les propriétés réservoir/géomécaniques (lithofaciès, pression, température, saturation en vapeur d’eau, etc.) sont aussi évaluées. Enfin, concernant l’interprétation sismique, des corps réservoir connectés (geobodies) sont extraits des attributs sismiques.

Modeling Steam Assisted Gravity Drainage (SAGD) can involve significant CPU (Central Processing Unit) time when both thermal fluid flow and geomechanics are coupled in order to take into account variations of permeability and porosity inside the reservoir due to stress changes. Here, a numerical procedure that performs thermo-hydro-mechanical simulations, in an efficient way, is presented. This procedure relies on an iterative coupling between a thermal reservoir simulator based on a finite volume method and a geomechanical one based on a finite element method. A strong feature of this procedure is that it allows handling the case when the reservoir simulations are performed using Adaptive Mesh Refinements (AMR). It thus provides an accurate description of the steam front evolution and allows taking geomechanical effects into account without performing the geomechanical simulations on a refined mesh. The efficiency of this coupling procedure is illustrated on a synthetic but realistic SAGD test case.

Summary Approximately one-third of global heavy-oil resources can be found in fractured reservoirs. In spite of its strategic importance, recovery of heavy crudes from fractured reservoirs has found few applications because of the complexity of such reservoirs. In-situ combustion (ISC) is a candidate process for such reservoirs, especially for those where steam injection is not feasible. Experimental studies reported in the literature on this topic mentioned a cone-shaped combustion front, indicating that the process was governed by diffusion of oxygen into the matrix. The main oil-production mechanisms were found to be thermal expansion of oil and evaporation of light components (Schulte and de Vries 1985; Greaves et al. 1991). In order to confirm these results, we carried out reservoir-simulation studies presented in Fadaei et al. (2010). We have shown that the front has the shape of a cone, and we have performed a combustion/extinction analysis representing the results in a diagram of cumulative production vs. diffusion coefficient and matrix permeability. Before obtaining quantitative and qualitative comparisons, we need to characterize the systems we want to study. Therefore, we also carried out laboratory experiments using kinetic cells and combustion tubes. The kinetic-cell studies showed that the presence of carbonates has a significant effect on combustion kinetics. Our combustion-tube studies confirmed the previously observed coneshaped front. Previous studies reported in literature used heating elements along the combustion tube to regulate the temperature, which may have caused some undue heating of the core. To avoid that, we chose to use efficient insulation to minimize heat losses. Combustion advanced faster in nonconsolidated matrix, in which the permeability was higher than in consolidated matrix. The results showed that the presence of severe heterogeneities may prevent the combustion front from propagating. Several runs were performed for different air-injection rates and pressures and for different permeability contrasts between the matrix and the fracture. The next step of our work is the upscaling of ISC in the fractured reservoir at interwell scale on the basis of knowledge provided by simulation and experimental studies.

Steam Assisted Gravity Drainage (SAGD) is a thermal process that has found wide application in high permeability heavy oil or bitumen reservoirs, mainly in the Western part of Canada. In this process, steam injection continuously modifies reservoir pore pressure and temperature, which can change the effective stress in the reservoir, resulting in a complex interaction of geomechanical effects and multiphase flow in the cohesionless porous media. Quantification of the state of deformation and stress in the reservoir is therefore essential for the correct prediction of reservoir productivity but also for the interpretation of 4D seismics used to follow the development of the steam chamber. On another side, this quantification is crucial for the evaluation of surface uplift, risk of loss of seal integrity, hydro fracturing and well failure. Simultaneous study and analysis of interrelated geomechanics and fluid flow in the reservoir are thus crucial for the management of the process at different stages. The objective of this paper is to show the importance of taking into account the role of geomechanics in the numerical modelling of SAGD and to provide a better description of the rock contribution to fluid flow in this process. A geomechanics- reservoir partially coupled approach is presented that allows to iteratively take the impact of geomechanics into account in the fluid flow calculations and therefore performs a better prediction of the process. The proposed approach is illustrated on a realistic field case.

Summary This paper presents an integrated workflow for the interpretation of 4D seismic data to monitor steam chamber growth during the steam-assisted gravity drainage recovery process (SAGD). Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, fluid saturations, pore pressure, and so on. The workflow is based on the generation of a geological model inspired by a real field case of the McMurray formation in the Athabasca region. The approach consists of three steps: the construction of an initial static model, the simulation of thermal production of heavy oil with two coupled fluid-flow and geomechanical models and the production of synthetic seismic maps at different stages of steam injection. The distribution of geological facies is simulated on a fine grid using a geostatistical approach, which honours all available well data. The reservoir's geomechanical and elastic properties are characterized by logs and literature at an initial stage before the start of production. Production scenarios are run to obtain pore pressure, temperature, steam and oil saturations on a detailed reservoir grid around a well pair at several stages of production. Direct coupling with a geomechanical model produces volumetric strain and mean effective stress maps as additional properties. These physical parameters are used to compute new seismic velocities and density for each stage of production according to Hertz and Gassmann formulas. Reflectivity is then computed, and a new synthetic seismic image of the reservoir is generated for each stage of production. The impacts of heterogeneities, production conditions and reservoir properties are evaluated for several simulation scenarios from the beginning of steam injection to 3 years of production. Results show that short-term seismic monitoring can help in anticipating early changes in steam injection strategy. In return, long-term periods allow the behaviour of the steam chamber to be monitored laterally and in the upper part of the reservoir. This study demonstrates the added value of 4D seismic data in the context of steam-assisted heavy oil production.

The performance of heavy-oil production by Steam-Assisted Gravity Drainage (SAGD) can be affected by near-well reservoir heterogeneities. However, as many factors interact during thermal production such as changes in oil viscosity, fluid saturations, pore pressure, stresses..., the monitoring of the steam chamber growth by 4D seismic data is not direct. An integrated workflow is presented. Based on a Canadian heavy oil field, the approach consists of three steps: 1/ the construction of an initial static model, 2/ the simulation of the thermal production of heavy oil with two coupled fluid-flow and geomechanical models, 3/ the production of synthetic seismic cubes at different stages of steam injection. The impacts of heterogeneities, production conditions and reservoir properties are evaluated for several production stages. Results show that heterogeneity distribution has a strong impact on mechanical results and then on the synthetic 4D seismic data. This study also highlights the impact of the shale mechanical behaviour on the steam chamber development during thermal production. Finally, this study demonstrates the added value of 4D seismic data in the context of steam-assisted heavy oil production.

Summary Simulation of an in-situ combustion (ISC) process was performed for a fractured system at core and matrix-block scales. The aim of this work was: (1) To predict the ISC extinction/propagation condition(s), (2) understand the mechanism of oil recovery, and (3) provide some guidelines for ISC upscaling for a fractured system. The study was based on a fine-grid, single-porosity, multiphase, and multicomponent simulation using a thermal reservoir simulator. First, the simulator was validated for 1D combustion using the corresponding analytical solutions. 2D combustion was validated using experimental results available in the literature. It was found that the grid size should not be larger than the combustion-zone thickness in order for the results to be independent of grid size. ISC in the fractured system was strongly dependent on the oxygen diffusion coefficient, while the matrix permeability played an important role in oil production. The effect of each production mechanism was studied separately whenever it was possible. Oil production is governed mainly by oil drainage because of gravity force, which is enhanced by viscosity reduction; possible pressure-gradient generation in the ISC process seems to have a minor effect. The nature (oil-production rate, saturations distribution, shape of the combustion front) of ISC at core scale was different from that in a single block with surrounding fracture. The important characteristics of different zones (i.e., combustion, coke, and oil zones) at block scale were studied, and some preliminary guidelines for upscaling are presented.

The performance of heavy-oil production by Steam-Assisted Gravity Drainage process (SAGD) can beaffected by near-well reservoir heterogeneities. However, as many factors interact during thermalproduction such as changes in oil viscosity, fluid saturations, pore pressure, stresses,... the interpretation of4D seismic data in terms of steam chamber geometry is not direct nor unique.

Summary It has been widely recognized that formation damage caused by drilling fluid has a huge impact on well productivities. The degree of formation damage can be studied using a numerical model. However, uncertainties in the prediction of productivity loss need to be investigated. To quantify these uncertainties, experimental designs combined with the Response Surface Methodology (RSM) are used to assess the impact of uncertain parameters on formation damage. This approach allows to identify the most influential parameters on well productivity loss and to estimate the risks of formation damage. A good control of the most sensitive parameters can limit productivity loss. This approach provides key recommendations for the selection of drilling fluid to maximize well performance.

In spite of its strategic importance, the topic of recovery of heavy crude oils from fractured carbonate reservoir has not been extensively addressed. Thermal methods seem well suited for this kind of problems, particularly in situ combustion has shown promising results in laboratory experiments. Extensive work has been done on development of thermal process simulator but for the in-situ combustion applied specially in fracture reservoirs where one is dealing with multi-scale multi-process problem, many unknowns are still exist. The recovery mechanism, reservoir and operational conditions on which the combustion can propagate in fractured systems are not enough clear. Also due to safety issues, air injection required careful assessment of the reservoir displacement mechanisms in particular the magnitude and the kinetics of matrix-fracture transfers. To understand the mechanism of heavy oil recovery from a fractured reservoir we propose the development of a numerical simulation strategy, starting from existing simulation tools that are adapted to this particular problem. This will allow firstly understanding the role of each driving mechanism and physical as well as operational parameters in recovery process and secondly choosing the suitable up-scaling method. The study is based on the fine grid, single porosity, multi-phase and multi-component simulation of a core surrounded by two parallel air invaded fractures using the thermal simulator. Firstly the simulator is validated for different processes: one and two dimensional diffusion and one-dimensional combustion are compared with the corresponding analytical solutions. The two-dimensional combustion is validated using experimental results available in the literature. The simulation results predict the conditions on which the combustion is sustained in the fractured reservoir as a function of oxygen diffusion coefficient, injection rate, and the permeability of the matrix. Oil production via natural drainage, hot fluid injection and in-situ combustion are compared to address the importance of different driving mechanisms. At the block scale the effect of fracture spacing, heterogeneity in the matrix and the grid size on the propagation of combustion and the oil production are studied and then a suitable up-scaling procedure is proposed.