Summary This study investigates the effect of clay type on the performance variations of steam-assisted gravity drainage (SAGD). Two SAGD experiments at identical experimental conditions were conducted. The reservoir rock for the first experiment (SAGD1) is prepared with a sand (85 wt%) and kaolinite (15 wt%) mixture, and the second experiment (SAGD2) is prepared with a sand (85 wt%), kaolinite (13.5 wt%), and illite (1.5 wt%) mixture. The effectiveness of the steam-chamber growth did not change with the clay type; however, 15-wt% reduction in oil recovery was observed for SAGD2. The possible reasons were investigated with the analyses on the produced-water, the produced-oil, and the spent-rock samples. Contact-angle, particle-size, zeta-potential, and interfacial-tension measurements were carried out on the samples. The mineralogical changes on spent-rock samples were determined by X-ray diffraction (XRD) and scanning-electron-microscope (SEM) analyses. The contact-angle measurements on the spent-rock samples displayed the higher oil-wetness for SAGD2 than SAGD1. However, the water-wetness of illite is known to be higher than that of kaolinite. This unexpected result is explained by the interaction of illite and the asphaltenes from SAGD2. The particle-size measurements, along with the SEM images, on post-mortem samples reveal that illite containing clay exhibits cementation behaviour and, hence, reduces the permeability of the rock. According to the experimental results, we developed hypotheses to understand the bitumen/illite and bitumen/kaolinite interactions for SAGD. Because of the high water-wetness of illite, illite particles first interact with water. This interaction results in cementation and forms illite lumps with sand. Then, illite lumps continue to interact more vigorously with the polar molecules (water, asphaltenes, and resins). Clay migration and production occur in both clay types; however, while kaolinite is produced in the water phase, illite-containing clay as a result of its interaction with asphaltenes is produced in the oil phase.

Summary A geomechanical and fluid-flow coupled model was developed to simulate natural-fracture-network reactivation during hydraulic-fracturing treatments in shale gas reservoirs. The fractures were modelled using the continuum approach in a commercial finite-difference code, labeled the “softening ubiquitous joints” model, with randomly distributed strength parameters to describe heterogeneity along the fracture plane. The models allow for intersecting fractures to represent realistic scenarios. The permeability values in the fractures are dynamically updated during the simulations together with the reversible tensile opening because of elastic response and irreversible shear opening caused by plastic deformations. The reactivation of the fracture network resulted in high permeability along these fracture planes. The developed model can predict microseismic events caused by slip on the fracture planes. The magnitude levels of these microseismic events are comparable with the levels observed in events monitored by use of geophone arrays during hydraulic-fracturing treatments for different shale gas reservoirs.

Summary We present a systematic approach to integrate geoscience and dynamic reservoir modeling for two multiwell pads in the Horn River basin, Canada. The Horn River shale-gas play is a world-class unconventional gas resource and is being exploited by use of multistage hydraulic fracturing along horizontal wells. The two well pads, Pad-1 and Pad-2, selected for this study comprise eight and seven horizontal wells, respectively, with 1 to 7 years of production history. Numerical modelling of shale reservoirs has historically been a problematic low-confidence exercise because of the difficulties associated with inadequate characterization of the geologic framework of shale plays; the problems of estimating the properties of induced-fracture networks; and the complexities of capturing multiphase flow in fracture networks and wellbores during production, especially in the face of offset-well activity. This paper provides insights into these issues. The geoscience modelling activity begins with integrating information from cores, well logs, petrophysical analyses, and seismic data into a 3D geocellular model. At first, the model is built upon a simple lithostratigraphic concept, which is the basis of the numerical-flow-modelling exercise of Pad-1. The 3D geocellular model is thereafter thoroughly reworked to incorporate a sequence-stratigraphic perspective to the Horn River shale. This reworked geocellular model has a profound impact on the dynamic modelling of Pad-2. Also, hydraulic conductivity of induced and natural fractures is measured on Horn River core plugs at reservoir conditions to constrain conductivity values assigned to primary, secondary, and tertiary flow paths into dynamic reservoir modelling. As a result of the integrated work flow, we have achieved a history match allowing us to further understand the hydraulic-fracturing behaviour and its impact on producing shale reservoirs of the Horn River formation. On the basis of the findings, we recommend targeting the Evie and Otter Park shale reservoirs for landing horizontal wells and multistage fracturing when the Carbonate Fan is thin; this approach can produce all three compartmentalized shale reservoirs of the Horn River formation. Ultimately, the objective of any reservoir modelling project is to provide a range of reliable forecast of future performance that is grounded in representative geoscience interpretations and that takes operational constraints into account. The technical learnings described in this work will be helpful to further understand hydraulic-fracturing behaviour and its impact on producing shale reservoirs.

Summary A commercial supported catalyst was regenerated and reused for three combustion-tube tests to study the upgrading potential of Athabasca bitumen supplied by Japan Canada Oil Sand Ltd. (JACOS). These tests were part of a larger program of combustion-tube tests performed by the In-Situ Combustion Research Group (ISCRG) under the auspices of the Alberta Ingenuity Center for In-Situ Energy (AICISE). The tests were premixed and carried out at the same pressure of 3.45 mPa (500 psi), preheat temperature (95°C), and ignition temperature (350°C). Test 1 used a fresh supported catalyst. Test 2 used a regenerated catalyst retrieved from Test 1, and Test 3 used regenerated catalysts (second time regeneration of catalysts from Test 1) retrieved from Test 2. Significant hydrodenitrogenation (HDN), 52% for the fresh catalyst Test 1, 38.1% for regenerated catalyst Test 2 and 23.8% for regenerated catalyst Test 3, was obtained. The levels of hydrodesulfurisation (HDS) obtained were 18.1, 18.4, and 15.2% for Tests 1, 2, and 3, respectively. The significant HDN and HDS removal coupled with decreased viscosity, increased °API value, and light hydrocarbons indicate upgrading of the original Athabasca bitumen for all three tests. The results showed that although the regenerated catalyst Tests 2 and 3 lost HDN activity compared to the fresh catalyst, the regenerated catalysts were still active for repeated use for in-situ upgrading.

Summary Unconventional reservoirs require extensive hydraulic-fracturing treatments to produce fluids economically and efficiently. The main purpose of such treatments is to create complex fracture networks with high-conductivity paths deeper into the nonstimulated reservoir regions. Proppants play an important role in maintaining good-quality fracture conductivities, which then greatly affect long-term production performance. In addition, research on proppants has shown a reduction in conductivities under downhole stresses and multiphase-flow behaviours. Therefore, it is important to study the effect different proppants and conductivities have on production performance through actual field cases. To evaluate the production performance of wells completed with different proppants, the authors proposed an integrated work flow for characterization and simulation of unconventional reservoirs. This work flow is unique because of the stochastic fracture-network-generation algorithms and improved unstructured-grid-generation techniques. Both analysis of field-production data and numerical simulations were performed on eight wells in the CAPA field of North Dakota. For the field-data analysis, three public-data resources were reviewed to prepare a summary of reservoir properties, fracture properties, proppant properties, and production history. For the numerical simulations, all the wells were modelled and simulated with the proposed work flow. Finally, sensitivity analyses were carried out to investigate the effects of fracture conductivities and natural fractures. After completing the field-case studies and reservoir simulations, it was concluded that with the same fracture design, higher fracture conductivity improves production performance. Pumping a smaller volume of upgraded proppants with higher conductivity not only improves long-term production performance, but also justifies the additional costs and reduces the overall operation time of the entire hydraulic-fracturing job. The stimulated reservoir volume was greatly increased, as was the production performance, where natural fractures exist. In this paper, field-data analysis was applied in the Bakken to demonstrate the integrated unconventional work flow. The proposed unstructured-gridding algorithms can be incorporated into any preprocessor to handle complex networks. Reservoir, fracture, and proppant characterization and reservoir simulation of the field cases can help engineers prepare and interpret simulation input and output.

Summary Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone. Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure. An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process. The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage. In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer. Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.

This study provides methods that can be simply applied to constrain forecasts and improve accuracy for forecasting a large number of liquid-rich shale wells. Using simulation cases, the authors demonstrate that constant condensate/gas ratios (CGRs) can occur for tight/shale gas/condensate wells exhibiting transient linear flow and flowing at near-constant flowing bottomehole pressure and that single-phase forecasting methods can be applied, even if multiphase flow is occuring in the reservoir.

Caprock-integrity issues have been brought to the forefront with recent documented steam and bitumen leaks making their way to the ground surface, forcing the Alberta Energy Regulator (AER) to place a moratorium on the licensing of shallow thermal in-situ oil-sand projects. Reviewing core-acquisition, -storage, -analysis, and -preservation techniques can prevent potential project failure, capital loss, environmental liabilities, and public-safety risks. Responsible development of thermal projects requires that caprock integrity be quantified.

Summary During the past few years, several studies have analyzed the pressure-transient responses of hydraulically fractured horizontal wells in shale-gas reservoirs. However, that research included simplified models that reflected natural and hydraulic fractures -only, unlike real shale reservoirs. To develop an accurate shale-gas model, this study considers the effects of rejuvenated fractures as well as natural and hydraulic fractures. Rejuvenated fractures, regarded as an important specificity in this paper, are revitalized natural fractures created by hydraulic fracturing. To analyze the pressure-transient characteristics and productivity of fractured horizontal wells in shale reservoirs, extensive numerical simulations have been conducted. This model considers the effects of natural- and rejuvenated-fracture permeability, matrix permeability, parameters of hydraulic fractures (e.g., width, height, and half-length), and the range of stimulated reservoir volume. Results show a clear distinction between existing models and the proposed model. In the proposed model, the boundary induced by the rejuvenated fractures generates pseudoboundary-dominated flow. This work expands our insight into the pressure-transient characteristics of a hydraulically fractured horizontal well in a shale-gas system.

Summary One of the issues for the pipeline transportation of diluted bitumen (dilbit) is the fate and behaviour of the dilbit if it is spilled in freshwater systems; in particular, the evaporation rate and the change in physical properties of the film after evaporation and exposure to water (weathering). In this study, the evaporative weathering of dilbit Cold Lake Winter Blend (CLWB) and light crude oil Alberta Sweet Blend (ASB) films were compared. Evaporation rates were measured for films on glass over time (up to 30 days) at different air-flow rates and at temperatures of 5, 15, and 25C. The solvent content, density, and viscosity of the films were measured after different weathering times. A second set of tests at 15C was performed on both dilbit and light-crudeoil films on water. As expected, the mass-transfer rate increased with increasing temperature and decreasing film thickness in all cases. The evaporation of the dilbit was found to be limited by the diffusion rate of the lighter components through the film while that of the light crude oil was limited by convective mass transfer to the air above. The density and viscosity of both the CLWB and ASB films correlated to the amount of evaporated material at all conditions examined, including different film thicknesses, temperatures, and air-flow rates. It appears that the volatile components evaporate in the same order at any conditions; therefore, film composition, density, and viscosity are only functions of the amount evaporated. The evaporation rates, density, and viscosity of CLWB and ASB films weathered over water were identical to those corresponding films weathered on glass, within the error of the measurements; that is, contact with still water had no effect on weathering.

Summary In this viscoelastic model, shale creep deformation was characterized and rheological models were developed. It not only addressed instantaneous, transient, and long-term sample deformations, but also enabled the estimation of proppant-embedment depth during production. Creep deformation was most pronounced when water impregnated the shale; decaneimpregnated samples produced less creep deformation; and the least creep was measured when shale was dry. The theory of linear viscoelasticity was used to model the samples’ time-dependent deformation.

Summary Limited studies on oil recovery from naturally fractured reservoirs using low-temperature air injection show that the process is strongly dependent on oxygen (O2)-diffusion coefficient and matrix permeability, both of which are typically low. A new approach (i.e., the addition of hydrocarbon solvent gases into air) is expected to improve the diffusivity of the gas mixture and to accelerate the oxidation. To study this new idea, called low temperature air/solvent injection, laboratory tests were performed by soaking heavy-oil-saturated cores in air/solvent filled reactors to determine the critical parameters on recovery. Laboratory tests were complemented by conducting experiments using air at different O2 concentrations: zero (i.e., nitrogen), 21.0 mol% (air), and 37.3 mol% (O2-enriched air). For safety reasons, it is imperative that enough time be given for air diffusion before the injected air breaks through a highly permeable fracture network. This implies that the huff ‘n’ puff type of injection is a plausible option as opposed to the continuous injection of air. A high recovery factor was obtained by soaking a single matrix in an air/solvent chamber at static conditions rather than with air only. The period of pressure stabilization was faster for the air/solvent mixture than in 100% solvent. The asphaltene content was lower in the air/solvent case than in the 100%-air injection case. Instead of pure-hydrocarbon solvent, injection of an air/solvent mixture yields a better recovery with less asphaltene. This is expected to reduce the cost of the process compared with pure-solvent injection. At low temperatures (75C), O2 consumption in the matrix oil was low, while at high temperatures, the O2 was partially (150C) or totally (200C in the presence of propane) diffused and consumed in the matrix.

The various effects of a diffusion process on estimation of a gas-diffusion coefficient were studied in the complete paper. Considering both classical and recently attempted boundary conditions, the effects of taking into account the nonequilibrium nature of a diffusion process on estimation of mass-transfer parameters using pressure-decay data of carbon dioxide (CO 2 ), methanw(CH H ), and nitrogen (N 2 ) dissolution in Athabasca bitumen at two different temperatures were found to be negligible, considering the gas/oil-interface resistance on calculated values of diffusivities.

Oil production from the Bakken formation has been active for 60 years and has applied three well-completion-design strategies in three different eras: hydraulically fractured vertical wells before 1987; horizontal wells before 1991; and multiple-transverse-fracture horizontal wells since 2006. Reported production data enable comparisons of well performance during these eras. This study employs the log-log graph of rate (q) vs. material balance time (MBT) (Q/q) to diagnose transient (Slope 2;1=4 or 2;1=2) and boundary-dominated flow (BDF) (Slope 2;1) behaviour. Wells from the three eras show mainly three types of flow-regime sequences observed as straight trends on the log-log graph of rate vs. MBT: 2;1=4 to 2;1, 2;1=2 to 2;1, and 2;1=4 to 2;1=2 to 2;1. Flow geometries corresponding to various flow-regime sequences are related to specific well and formation characteristics. Then, we extrapolate the BDF behaviour to estimate the expected ultimate recovery (EUR) for each well when possible. We observed that both the average well EUR and the average well rate at start of BDF behaviour are highest for the multiple transverse- fracture-horizontal-well completion design. This project also investigates the behaviour of the gas/oil ratio (GOR) vs. MBT. Three types of GOR behaviour were observed: constant; constant followed by sharp increase; or scattered. In all three eras, the EUR was highest in wells with constant-GOR behaviour followed by a sharp increase. The sharp increase likely signals flow below the bubblepoint pressure. The lower EUR in wells that did not produce below the bubblepoint pressure shows that solutiongas drive behaviour enhances the EUR. Lower EUR in wells with scattered GOR behaviour may be attributed to unstable well production. This study shows how to use long-term production behaviour to gain important insights describing well designs and why some wells have higher EUR and rate behaviour.

Gas injection is considered as an effective recovery process that has been widely used in the worldwide oil industry. There are limited pilot field projects conducted on enhanced-oil-recovery (EOR) process by gas injection in shale-oil reservoirs. Although numerous studies have been conducted on gas injection in tight gas or oil reservoirs, the main recovery mechanism in shale-oil reservoirs is not well-understood. Diffusion plays an important role in the oil-recovery process in fractured-shale reservoirs. Most of the current studies on diffusion are performed in such a way that the producing pressure is equal to the initial reservoir pressure or core pressure; thus, the convective displacement is eliminated or minimized. One of the challenges is to evaluate the role of diffusion in field-scale displacements in the presence of viscous flow. This paper discusses the role of diffusion in improving oil recovery in fractured shale-oil reservoirs. Hoteit and Firoozabadi (2009) investigated the diffusion effect on recovery performance in a fractured gas/condensate reservoir. Their simulation results showed that molecular diffusion has a significant effect on gas recovery if the reservoir pressure is below the minimum miscible pressure. Modelling of the diffusion effect on ultimate oil recovery in extensively fractured shale reservoirs is crucial to the development of these marginal shale-oil or -gas projects. Evaluation of the recovery contribution from diffusion will provide important insights into the recovery mechanisms in intensely fractured shale-gas/oil reservoirs. Currently, a majority of the diffusion models were developed on the basis of the single porosity model that demands tremendous grid refinement in intensely fractured shale-oil reservoirs. The grid refinement is necessary for surrounding the fracture intersections, which makes the system become computationally expensive. In this paper, the matrix/matrix and matrix/fracture diffusion is coupled in a dual-permeability model to overcome the drawback of the single-porosity model. The simulation results demonstrate that the EOR by gas injection in the Eagle Ford shale-oil reservoir will benefit from matrix/matrix and matrix/fracture molecular diffusion.

The objective of this study was to develop reaction-kinetics models that can be used to describe the reactions of hydrocarbon fractions at various temperature conditions during the in-situ combustion (ISC) of Athabasca bitumen. In this work, a set of improved kinetic models—including low-temperature-oxidation (LTO), middle-temperature-oxidation (MTO), and high-temperature-oxidation (HTO) reactions—based on saturates, aromatics, resins, and asphaltenes (SARA) fractions in the crude oil are established. These kinetic models are used to reproduce the ramped-temperature-oxidation (RTO) experimental results through numerical simulation.

Research from this paper provides insight into the physical and chemical consequences of steam-assisted recovery of heavy oils and bitumens from sedimentary-rock reservoirs and reveals that geological and geochemical context is an essential consideration. To study mineral effects on gas production, the authors of the complete paper studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250 to 300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water-insoluble residues. All reaction products were studied with a variety of analytical techniques, including Fourier-transform infrared spectroscopy, chromatographic fractionation [saturate, resin, and asphaltene (SARA) analysis], gas chromatography mass spectrometry (GCMS), pyrolysis GCMS, and gas chromatography (GC) flame photometric detectors (FPDs)/thermal-conductivity detectors. These techniques were applied to whole oil, maltenes, and asphaltene fractions. Physical properties, including viscosity and density, were also measured.

Bitumen recovery is affected by the water-soluble acid species located in the working area, and this paper takes a look at those interactions and the outcomes each may have on oil-sands recovery. Varying parameters on recovery (e.g., oil-sands components, physicochemical and dielectric properties, and organic compounds found in water) are studied to determine the effects of adsorbed species and their interactions between the water-soluble compounds and bitumen present in oil sands. This research allows the industry to better determine both plans for heavy-oil recovery and water treatment.

The heavy-oil- and bitumen-recovery processes mainly intend to reduce the oil viscosity at the reservoir; therefore, the production and pipeline transportation of such viscous fluids require specific data on the viscosity and density of raw bitumen. In this study, the thermophysical properties of Athabasca bitumen were reported over a wide range of temperatures and pressures applicable for both in-situ-recovery methods and pipeline transportation of oil. The measurements were taken with our designed phase-behaviour experimental apparatus, capturing the density and viscosity of Athabasca bitumen accurately at temperatures varying from ambient temperature up to 200C and at pressures up to 10 MPa. The experimental density data for bitumen were correlated within 60.7 kg/m3 with a newly developed algorithm to obtain the coefficients of correlation equations, considering the influence of pressure and temperature on the density. The viscosity data are correlated reasonably (within 69%) over the studied conditions with two correlations, which include two adjustable parameters each.

The unconsolidated sands of the Lower Cretaceous McMurray formation are the primary host of the Athabasca oil-sands deposit in Alberta, Canada. Alberta has one of the world’s largest nonconventional hydrocarbon resources with an estimated 1.8 trillion bbl of heavy oil (ERCB ST98-2013). The Pike 1 Project is a joint venture between Devon Canada Corporation (operator) and BP Canada Energy Group ULC. The Pike 1 Project is currently under a multiyear appraisal program to evaluate the McMurray bitumen resources that are amenable to steam-assisted gravity drainage(SAGD). In the Pike 1 Project area, the particle-size distribution (PSD) of the middle McMurray reservoir sands is highly variable because of the complex nature of the depositional environment. In order to understand the McMurray reservoir sands, Devon has exercised rigorous laboratory sampling and quality-control procedures to confirm the comprehensiveness of the PSD data set. By use of an unsupervised hierarchical classification technique, a dynamically growing self-organizing tree algorithm was used to cluster all of the PSD histograms from within the bitumen net-pay zone into one of four sand classes on the basis of similarity. Each sand class has a distinct PSD and permeability range. Using the sand classes, Devon extracted select intervals of core that closely matched the PSD histogram of each class to provide physical samples, termed “sandprints,” to fulfill sand-control-testing objectives. Further work included integrating the sand classes within the Pike 1 geological model, 3D permeability mapping, and upscaled sand-class volumes for SAGD well-pad optimization. This paper describes the process by which Devon has evaluated and classified the Pike 1 PSD data set into distinct sand classes within the unconsolidated middle McMurray reservoir. Devon’s methodology of acquiring these sands, necessary for sand-control testing, is also discussed in detail, emphasizing the overall effectiveness of the process. By use of this innovative PSD classification process as a supporting tool to reservoir characterization, Devon intends to realize the following benefits: • SAGD horizontal-well-pair placement optimization • A more methodical approach to laboratory testing of horizontal-liner technology for SAGD producers and injectors • Improved reservoir management