bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Evolution of Water Saturations in the McMurray Oil Sands: A Product of Geological History and Capillary Pressure
Authors: James Bruce Rennie 
Published: June 2014

Abstract
This paper examines the role played by geological history and by capillary pressure in the evolution of the unusual water saturations of the McMurray reservoir of the Athabasca Oil Sands Region (AOSR). The McMurray formation water and bitumen have been a dynamic system evolving through geological time in order to maintain equilibrium between buoyancy and capillary pressure. The main driving force was the change in hydrocarbon as well as formation water density so that they became similar in value.
These changes were likely caused by a combination of factors including hydrocarbon biodegradation, reduction in temperature and pressure through erosion of the overburden above the McMurray, and lowering of water salinity. The weakening of buoyant forces would enable capillary pressure to increase the average water saturation and to redistribute water and hydrocarbon so that water was preferentially moved to areas with a higher fines fraction.
The paper reviews pertinent geological history and discusses theoretically how water saturation should have changed as a result of changes in oil/bitumen and in formation water density. Field data from two sites with different levels of biodegradation as well as a conventional non-biodegraded analogue were analyzed in light of the theoretical expectations.
There will be water saturations above irreducible levels and hence some water mobility throughout much of the McMurray. There also is evidence that the irreducible water saturation in good quality McMurray reservoir sands at one site is ~ 10% or less. It is possible that the present McMurray irreducible water saturation levels are somewhat similar to what they were at the time of first oil charge approximately 80 million to 110 million years ago.
High-water saturation zones form when biogenic gas in depleted gas caps is replaced by water, as concluded by Fustic at al., (2013). As water is drawn into the depleted gas cap from the surrounding reservoir, water saturation can be lowered to nearly irreducible levels at the base of the reservoir below. Capillary pressure can also create transition zones below these high-water saturation zones. Therefore, thin depleted paleo-gas caps could create zones of elevated water saturation much thicker than the original gas caps. There can be significant heterogeneity in these high-water saturation zones across the McMurray Formation and at field scale.
Experimental Studies: Shear Induced in Single Phase Permeability
Authors: Abdallah Ben Kais , Hamoud Mohamed , Chalaturnyk Rick 
Published: June 2014

Abstract
Absolute permeability plays an important role in reservoir engineering. Reservoirs like oil sands are shallow unconsolidated formations and stress dependent. During steam-assisted drainage (SAGD) the effective stress increases as results of either increasing in temperature or pore pressure. Rock properties for instance permeability will be induced by this change to influence therefore reservoir calculations.
To understand the behavior of stress-strain in unconsolidated reservoir during a SAGD, a series of drained triaxial compression tests were performed to study the shear-induced changes in absolute permeability at low stress conditions. The experimental program included stress-strain tests under two different paths: isotropic unloading and increasing of mean stress was followed by permeability tests at each levels of strain and at different confining effective stresses.
Results from this study showed a substantial increase of absolute permeability in the lower case of 50 kPa of effective confining stress. This gain was up to 88%. In the higher level of effective confining stress, however, there was a decrease of absolute permeability.
The aim of this project was to provide an empirical correlation linking the absolute permeability to effective confining stress and volumetric stain so that the behavior of absolute permeability at different overburden depths will be understood.
Coupled Wellbore/Near-Well Flow and Geomechanical Thermal Simulation of Cyclic Steam Stimulation with Different Geometric Fractures
Authors: Li Ran , Chen Zhangxin , Xu Jinze , Zhong He 
Published: June 2014

Abstract
Cyclic steam stimulation (CSS) is a commercial in situ recovery method that involves injecting steam into formations at high pressure to reduce the viscosity of heavy oil and bitumen. The injection pressure is typically above the reservoir fracture pressure to induce fractures, which can improve reservoir permeability and fluid mobility. Geomechanics and heterogeneities near a well significantly affect reservoir fracturing, particularly under thermal conditions. In addition, oversimplified descriptions of fracture geometry may fail to represent actual reservoir performance. Thus modeling near-well flow effects coupled with geomechanics is essential for detailed large-scale thermal simulations with fractures. Conventional methods have exhibited limitations in capturing interactions among wellbore/near-well flow, geomechanics, and fluid flow during CSS development. Therefore, flow/stress/near-well flow coupling under different fracture geometries is investigated in this study.
A facies-controlled geostatistical model is first constructed for a Cold Lake reservoir to obtain more reliable results. A fully coupled model is further generated from this geological model. After local grids near wells are refined, we construct different fracture geometries by changing the fracture length and direction. In this study, uncertainty analyses on fracture geometry near the vertical wells are performed. The simulation results show that omitting geomechanics and wellbore modeling increases oil recovery. Moreover, oversimplified fracture geometry with simple planes overestimates an oil rate. Furthermore, fractures with complex geometries and geomechanics exhibit high conductivity and provides effective channels for steam and bitumen but at the same time, it may cause steam channeling and decrease the efficiency of steam injection.
Upscaling Study of Cyclic Solvent Injection Process for Post-CHOPS Reservoirs through Numerical Simulation
Authors: Zhang Min , Du Zhongwei , Zeng Fanhua , Xu Suxin 
Published: June 2014

Abstract
Cyclic Solvent Injection (CSI) is the most promising process for a post-CHOPS reservoir (Chang and Ivory 2012). Experimental studies suggest that oil recovery can reach up to 62% at the lab scale, which indicates the potential viability of the CSI process. This paper summarizes experimental results of six CSI tests with three physical models with different scales. Typical western Canadian heavy oil sample with a viscosity of 4830 cp at the reservoir conditions was used. Numerical simulation models were established to simulate these tests. The uncertainties in upscaling CSI process, such as relative permeability curve, capillary pressure, reaction rate in foamy oil model and dispersion coefficient were investigated by numerical simulation. In history-matched cases, the same relative permeability curves were obtained for these six CSI tests only with different capillary pressure. Sensitivity analysis illustrates that adding an appropriate capillary pressure in each test could refine the match results between simulation and experimental data. Generally, the larger the model is, the smaller the capillary pressure is. Therefore, the capillary pressure may be neglected in field scale applications. In addition, the location of the wormholes may affect the magnitude of capillary pressure employed in history-matched cases.
A typical western Canadian heavy oil post-CHOPS reservoir (M-reservoir) was employed to study the uncertainties during the CSI process by numerical simulation. The uncertain parameters include oil relative permeability, gas relative permeability, capillary pressure and dispersion coefficient. The Design of Experiments (DOE) method was utilized to define the simulation matrix, and 18 simulation cases, with 7 factors in 3 levels, were run. The multiple inferences were covered as much as possible. The oil recovery factor for ten-year production was selected as the response variable. The range between 18 estimates and "standard" value (14.611%) in terms of the recovery factor was from 0.04% to 1.42%. After that, the multiple-linear regression was performed to construct the response surface in DOE and the proxy equations were then generated. Three thousand Monte-Carlo simulations, in total, were performed to generate the probability distribution functions, which indicated that the P90, P50 and P10 estimates of the oil recovery factors were 14.08%, 14.69% and 15.33%, respectively. This study demonstrates that through simulating experiments from physical models with different scales, the uncertainties in predicting the field-scale CSI performance can be significantly reduced.
New Insights on Chemical EOR Processes for Heavy Oil
Authors: Hocine S. , Magnan A. , Degré G. , Rousseau D. , Rousseau N. 
Published: June 2014

Abstract
Chemical EOR methods have become an increasingly attractive option for heavy oil reservoirs where thermal methods cannot be applied, like in thin reservoirs. The use of surfactants for heavy oil is only reported, both at lab and field scale, in a limited number of cases and mostly in combination with alkali to benefit from the generation of in-situ surfactants. However, operational issues (such as scale or corrosion) associated with the use of alkali as well as negative impacts on project logistics are often mentioned. The objective of this work is to demonstrate at lab scale the efficiency of alkaline-free surfactant-polymer processes in the context of heavy oil reservoirs.
The present investigation is focused on a Canadian heavy oil (14°API and 1400 cP) in representative reservoir conditions (high permeability sandstone, temperature of 35°C, low salinity). A dedicated synthetic surfactant formulation is designed using a screening methodology based on a robotic platform. Ultra-low interfacial tensions are evidenced from phase behavior and confirmed by spinning-drop tensiometry. Oil recovery performances of the surfactant formulation are then evaluated in corefloods.
Cores at Swi are first polymer flooded until no oil is produced to reach a residual oil saturation. Surfactant-Polymer formulations are then injected. Typical results show that additional oil is produced as a continuous oil bank (up to 100% ROIP depending on the slug size) and with a moderate adsorption if a salinity gradient strategy is applied (typically 0.2 mg surfactant per g of rock). This indicates that the surfactant is able to mobilize most of the residual oil. The results of this exploratory investigation show that alkaline-free surfactant-polymer processes could be applied to heavy oil reservoirs while minimizing operational issues. Complementary work will also be presented on optimization of the process through injection strategy improvement and surfactant dosage reduction as well as on extrapolation of the lab results to field-scale technical and economical feasibility.
Practical Implementation of Knowledge-Based Approaches for SAGD Production Analysis
Authors: Ma Zhiwei , Leung Juliana Y. , Zanon Stefan D. , Dzurman Peter J. 
Published: June 2014

Abstract
Quantitative appraisal of different operating areas and assessment of uncertainty due to reservoir heterogeneities are crucial elements in optimization of production and development strategies in oil sands operations. Although detailed compositional simulators are available for recovery performance evaluation for SAGD, the simulation process is usually deterministic and computationally demanding, and it not quite practical for real-time decision-making and forecasting. Data mining and machine learning algorithms provide efficient modeling alternatives, particularly when the underlying physical relationships between system variables are highly complex, non-linear, and possibly uncertain.
In this study, a comprehensive training set encompassing SAGD field data compiled from numerous publicly-available sources is studied. Exploratory data analysis is carried out to interpret and extract relevant attributes describing characteristics associated with reservoir heterogeneities and operating constraints. Because of their ease of implementation and computational efficiency, knowledge-based techniques including artificial neural networks (ANN) are employed to facilitate SAGD production performance prediction. Predicting (input) variables including porosity, net-to-gross ratio, saturation, gross pay, normalized shale barrier thickness and distance to well pair, and initial production rate are formulated. Measures such as cumulative production over discrete time intervals are considered as prediction (output) variables. Data records that are comprised of both input and output variables are assembled; the network is trained using the data set to identify all significant patterns and relationships that exist between the input and the output variables. The model is subsequently validated using a cross-verification procedure, during which records that have been excluded at the training stage are presented to the model.
This paper demonstrates that knowledge-based techniques can be implemented in a practical manner to analyze large amount of competitor data efficiently. The approach can be integrated directly into most existing reservoir management routines. It can also be readily updated when new information has become available. Given that robust reservoir management and real-time decision-making are major challenges faced by the industry, the data-driven models presented in this paper has great potential to be applied in other recovery projects such as solvent-aided steam injection.
Wellbore modeling and design of Nozzle-Based Inflow Control Device (ICD) for SAGD wells
Authors: Shad Saeed , Majdi Yazdi Mehdi 
Published: June 2014

Abstract
Production of bitumen from heavy oil reservoirs is a complex process due to high oil viscosity and heterogeneity of reservoirs. Steam assisted gravity drainage (SAGD) process have been applied to Western Canadian bitumen reservoirs as a feasible and technically effective process to produce heavy oil and bitumen. Considering cost associated with SAGD process and complexity involved in this recovery method, it is vital to optimize design and operation of SAGD to achieve the maximum return. Horizontal wells have become an indispensable component of SAGD process. Therefore, optimizing and improving their design will have significant impact on SAGD recovery method. Despite the fact that horizontal wells improve reservoir access, they suffer from high frictional pressure loss due to their long lengths. In addition, combination of limited control points on horizontal wells (toe and heal) and reservoir quality variation along the well and in the reservoir, poses significant challenges in well control and production optimization. One solution for such issues is the use of Inflow control devices (ICD). ICD's equalize and balance the pressure drop in the wellbore by shortening the flow paths, choking back the steam, and changing pressure potential to velocity potential and provide us with better well control.
In this paper, a SAGD well pair with eccentric dual tubing completion is numerically modeled. The numerical modeling consists of a history matching step that is followed by five years of production forecast. The base case is compared with several scenarios with nozzle ICD's installed on the producer well. The simulation cases with ICD include different nozzle sizes and various compartmentalization schemes along the wellbore. The results show how ICD's can improve well performance and increase efficiency of the SAGD process.
With the sensitivity analysis done using numerical simulation results, the optimum number of ICD's and nozzle size is proposed based on several screening criteria such as low SOR, steam chamber uniformity, high steam chamber temperature, low subcool, and low steam production.
This study reveals the advantages of ICD-equipped wells over the conventional dual-tubing and slotted liner completions for SAGD operation. The improved well performance, increased bitumen production, and longevity of the wells will compensate for additional cost of ICD installation in a short period of time.
Advances in Electrical Heating Technology for Heavy Oil Production
Authors: Sandberg Chet , Thomas Keith , Hale Arthur 
Published: June 2014

Abstract
Electrical downhole heating has been used for many years for flow assurance and now is being adapted for reservoir stimulation, viscosity reduction and "in situ" conversion of heavy oil. This paper starts with a short review of flow assurance applications in Alaska and Canada as described in SPE-165323-MS. It then reviews the current and developing technology and some of the heat transfer parameters for use of high voltage high power electrical heaters in a number of types of applications. In the past heater voltages have been limited to below 600 volts for mineral insulated cable heaters. Significant material and processing advances have now permitted operation at 4160 volts. This has a number of operational advantages in providing longer length heater capabilities and less parasitic heating loss in the overburden. MI cable production technology is now available to fabricate MI cable heaters that can produce 1600 meters lengths without external splices. The thermal heat transfer from the well casing to the reservoir is usually the limiting factor on the amount of energy that can be transferred from the electrical heater to the formation. Both constant power and constant temperature heaters are explained with the emphasis on in operation reliability of each type of heater. The paper concludes with an economic analysis of the opportunity provided by a high voltage MI cable heater system in a horizontal well.
Numerical Thermal Simulation and Optimization of Hybrid CSS/SAGD Process in Long Lake with Lean Zones
Authors: Xu Jinze , Chen Zhangxin , Yu Yanguo , Cao Jili 
Published: June 2014

Abstract
Cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD) are successful commercial methods for enhanced oil recovery (EOR) used in Canada. Although SAGD exhibits higher oil recovery than CSS, it is more sensitive to reservoir heterogeneities such as top water and lean zones. In most cases, these baffles cause channeling in steam injection operations, thus leading to a high steam-oil ratio (SOR) and low injectivity. Therefore, recovering bitumen by using SAGD in a pilot well pad with such baffles in Long Lake has been a considerable challenge. To overcome the aforementioned issues, a hybrid process that combines CSS and SAGD (hybrid CSS/SAGD) is investigated in this study. Hybrid CSS/SAGD takes advantage of the benefits of both methods. During this process, all SAGD wells operate as cyclic injection/production wells. When the wells are shut in for a soak period, the injectivity of SAGD is highly improved. Simultaneously, the producer can also function as a heat source. After good conductivity is achieved between the injector and the producer, oil recovery is improved significantly.
This study aims to construct a hybrid CSS/SAGD simulation model for the Long Lake pilot well pad. The simulation is based on a well-defined 3D geostatistical model. By strictly controlling detailed lithological facies, lean zones and top water zones are accurately described in the geological model. These baffles are mainly located in the upper-middle portion of the McMurray Formation. By adjusting relative permeability curves, a SAGD model with a ten-year production history (beginning in April 2003) is history matched well. Based on this model, we then run hybrid CSS/SAGD simulations by changing well constraints from April 2003 with a submodel of well pair 1. Both wells in the well pair 1 operate as producers and injectors. The simulation results show that CSS-SAGD exhibits higher oil recovery and lower SOR than SAGD alone. Moreover, sensitivity analysis on preheating pressure is performed. Based on the net present value, we optimize the steam injection pressure and steam injection rate to establish criteria for each parameter for the pilot well pad.
The Successful Application of Automated Managed Pressure Drilling (MPD) To Protect Caprock Integrity by Narrow Margin Drilling in SAGD wells
Authors: Osayande Nadine , Mammadov Elvin , Sephton Sheldon , Boucher Vincent 
Published: June 2014

Abstract
The Canadian SAGD (Steam Assisted Gravity Drainage) industry continues to grow with more wells being drilled in Alberta that cannot be mined. Drilling issues addressing low reservoir pressure, tight well spacing, highly pressurized steam injection, cap rock integrity and tight drilling windows are currently some of the challenges that are being faced today.
As the industry looks for a way to improve and mitigate both drilling and environmental issues, this paper presents a drilling solution on applying an automated MPD (Managed Pressure Drilling) technique proven to identify and react to the actual wellbore pressures. This can detect and control any gain and losses within liters, while still having the ability to maintain a CBHP (Constant bottom hole Pressure) while drilling through tight windows.
This document demonstrates the successful application of advanced automated MPD technologies on Suncor's Dover well close to Fort McMurray, Alberta and will also elaborate on recommended operational procedures, equipment set up and to process flow diagrams along with the analyzed graphical data. The results demonstrated a successful re-drill of a producer well within an over pressured reservoir induced by steam injection, by using near water density mud weights, minimizing mud losses, preventing any steam or bitumen intrusion by monitoring return density to surface while maintaining bottom hole pressure within a narrow operating window.
Multi-stage Cleaning for Routine Core Analysis in Heavy Oil-bearing Carbonates, Campos Basin, Brazil
Authors: Borre Mai K. , Coffey Brian P. 
Published: June 2014

Abstract
Reservoir characterization of carbonate pore systems with both movable and non-movable phases of hydrocarbon (HC) was improved by use of a modified, multi-stage core cleaning procedure. Analyses were completed on core plugs collected from a 60 m carbonate-dominated core with highly variable depositional textures and pore networks. Rock fabrics included grain-dominated carbonates of variable size and sorting, framework-supported carbonates with finer interstitial matrix, and mixed carbonate-siliciclastic sands with a higher degree of grain sorting.
A modified workflow for sample cleaning was developed in collaboration with Weatherford Laboratories. The multi-stage workflow describes more accurately in-situ reservoir quality in reservoirs with heavy HC fractions, and it is applicable to carbonate and siliciclastic reservoirs. For this study, samples were first cleaned with a lighter solvent to remove only movable fluids from pore networks. Following measurement of effective porosity and permeability, the samples then were cleaned by standard solvents to remove all soluble fluids. After final cleaning, total porosity and permeability was measured.
When cleaned for movable fluids only, core plug porosity is comparable with NMR wireline data that estimate porosity related to movable fluid phases. The standard cleaning workflow yielded total porosity that resembled more conventional log-derived total porosity from density and neutron porosity log data. The difference in the permeability measured between these two cleaning methods often varied by an order of magnitude.
This cleaning methodology resulted in a more accurate depiction of reservoir quality and improved validation of wireline log data. When integrated with other datasets to better document the controls on reservoir quality and porosity distribution, these results provided valuable insight into the differentiation between in-place and recoverable hydrocarbons in this heavy oil-dominated petroleum system.