bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Dead Oil Viscosity and Injected Solvent Type on SVX Process Performance
Authors: Knorr Kelvin(Kelly) D , Imran Muhammad 
Published: June 2013

Abstract
This work presents experimental results of four 3D physical model experiments that were performed to evaluate the dependence of solvent vapour extraction (SVX) recovery process performance on initial dead oil viscosity and injected solvent mixture composition. Model excavation studies were also performed to approximate the solvent movement in the physical model and to map out the residual oil saturation and precipitated asphaltenes.
All of the four experiments — designated as SVX 14, 15, 16 and 17A — were performed on a 3D physical model (having permeability and porosity of ~4 darcy and ~33%, respectively) that was oriented vertically to provide model dimensions of 2.5 m thick by 0.2 m wide by 0.5 m long. The 0.5-m-long horizontal top injection and bottom production wells were separated laterally across the width and vertically across the thickness. Prior to solvent injection the model was resaturated with live oil containing methane at a gas/oil ratio ranging from 8.5 to 11 sm3/sm3. The initial dead oil viscosity at 21°C for SVX 14, 15, 16 and 17A were approximately 13,000, 33,000, 16,000, and 48,000 mPa•s, respectively. The composition of the injected solvent mixture for SVX 14 and 15 was ~57/43 mol% of methane (C1)/propane (C3) and for SVX 16 and 17A was ~57/43 mol% of carbon dioxide (CO2)/propane (C3).
The analysis of the experimental results revealed that the initial dead oil viscosity had a significant effect on the SVX performance. Higher oil production rates were achieved with the lower viscosity oils for both injected solvent mixture types, with a more pronounced effect observed when using the CO2/C3 solvent mixture. The results also showed that the CO2/C3 mixture resulted in earlier solvent breakthrough and initial oil production, reduced solvent makeup requirements (i.e., better solvent recycle stream), and reduced solvent retention in the model/reservoir, as compared to the C1/C3 solvent mixture. The residual oil saturation mapping showed that the CO2/C3 mixture led to comparatively lower values in the drained regions and higher amount of precipitated asphaltenes remaining in the model, although there was evidence of some precipitated asphaltenes close to both the injection and production wells in all four experiments, regardless of the solvent mixture type. Finally, this mapping also indicated that the solvent/oil interfaces and solvent chambers were more uniform and predictable for the CO2/C3 solvent mixture injection.
The field scale application and optimization of SVX processes requires that relationships be established among oil production rates, solvent utilization, and important process parameters such as matrix permeability, initial oil viscosity, solvent mixture composition, solvent utilization, etc. This work has attempted to generate such relationships for the two most promising mixed solvent systems being considered for use in heavy oil reservoirs.
A Novel Solvent Injection Technique for Enhanced Heavy Oil Recovery: Cyclic Production with Continuous Solvent Injection
Authors: Jiang T. , Jia X. , Zeng F. , Gu Y. 
Published: June 2013

Abstract
Solvent-based in-situ enhance oil recovery (EOR) techniques are extensively studied to improve oil recovery factors (RFs) for heavy oil reservoirs. Continuous injection, such as vapour extraction (VAPEX), and cyclic injection, such as cyclic solvent injection (CSI) are two main categories of solvent EOR techniques. The production rates of VAPEX are low in field tests. CSI does not show exciting results due to the quick reservoir pressure depletion and the sudden reservoir energy loss, which causes the oil to regain its viscosity.
A new enhanced heavy oil recovery technique, cyclic production with continuous solvent injection (CPCSI), is proposed in this paper. In this process, a vapour solvent is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flood the diluted oil out through an injector that is located on the top of the reservoir, while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to validate the CPCSI performance by using different sand-pack models with 4&not;-5 Darcy permeability, and saturated with Western Canada heavy oil sample. Gaseous propane is continuously injected through an injector at a constant pressure, which is below the dew point pressure, and producer was operated with a cycle of 50-minute-shut-in/10-minute-open period.
Experimental results show that, the oil is diluted and drained down by gravity during shut-in period, then produced in producer opening period by solution gas drive and gas flush. In comparison with VAPEX and CSI, CPCSI offers free gas driving, and still keeps oil diluted in the well opening period and produced by the gas flush. The RFs are up to 85% of OOIP in 1-D tests. Also, shorter height model has highest average production rate in comparison with others. Test results are also validated by 2-D physical model, in which the RF is improved by 11% by using the lateral CPCSI compared with classic lateral VAPEX. Well configurations and the shut-in/open scenarios are key optimization factors that affect CPCSI performance.
This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in-situ EOR techniques for Western Canada heavy oil reservoirs.
Integrated Solution for Underbalanced Perforation and Wellbore Clean Up as an Alternative Methodology
Authors: Mohamed H. N. , Osuji-Bells G. A. , Khalid M. Zaidan , Khaira K. , Lafontan J. , Ismail M. Rizal 
Published: June 2013

Abstract
Conventionally, a well completion would involve perforating the reservoir followed by a separate run to clean up the wellbore from perforating debris and burrs on the casing and liner to prevent damage to the completion packer when passing through the perforated interval. This is especially prevelant in dual completion and single selective completion wells where the lower packer will have to be run past the upper set of perforations. The wellbore clean up bottomhole assembly typically consists of a drill bit scraper and magnets run between the perforating and well completion phases.
As a result of the increasing emphasis on reducing operating costs and increasing operating efficiency, a new system was designed for perforating wells in underballanced condition and performing post perforation wellbore clean up in the same run by using standard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the perforating and wellbore clean up equipment operations are required.
Five jobs have been performed employing this combined underballanced perforating and wellbore clean up technique which have resulted in significant savings in rig time and increased operating efficiency. This paper summarizes the practical experiences gained during the development and deployment of this integrated perforating and wellbore clean up technique.
Efficient Displacement of Heavy Oil using Three Hydrocarbon Phases
Authors: Okuno R. , Xu Z. 
Published: June 2013

Abstract
Mixtures of oil with solvent gas can exhibit three-hydrocarbon-phase behavior at reservoir conditions, where the solvent-rich liquid (L2) phase coexists with the gaseous (V) and oleic (L1) phases. Three-hydrocarbon-phase behavior has been studied in the literature for CO2 floods and enriched gas floods at relatively low temperatures. Prior research on heavy-oil displacement with enriched gas presented that displacement efficiency at a given throughput can be non-monotonic with respect to gas enrichment. Slim-tube experiments for such displacements showed that oil recovery increased first, then decreased, and increased again with increasing gas enrichment. An optimum displacement with a high efficiency of more than 90% was observed when three-hydrocarbon-phase flow was present. However, detailed mechanisms for such an optimum displacement with three phases have not been explained in the literature.
In this research, we investigate mass transfer on multiphase transitions between two and three phases for three-hydrocarbon-phase displacements. Simple conditions are derived for the multiphase transitions that yield high local displacement efficiency by three hydrocarbon phases. The derivation is based on the generalized jump conditions for a multiphase transition shock from analytical theory of one-dimensional gas injection. The conditions derived are applied to explain non-monotonic oil recovery in quaternary displacements and the West Sak oil displacements.
Oil recovery at a given throughput can be non-monotonic with respect to pressure or gas enrichment. Such a non-monotonic trend can occur when local oil displacement by three hydrocarbon phases becomes more efficient, but slower, with decreasing pressure or decreasing gas enrichment. An optimum pressure or enrichment can occur as a consequence of the balance between the local displacement efficiency and the propagation rate of three hydrocarbon phases. The West Sak oil displacement with enriched gas studied in this research yields a high displacement efficiency of more than 90% at 1.5 hydrocarbon-pore-volumes injected at 53% methane dilution.
SAGD Pad Performance in an Ultra-Defined Athabasca Point Bar Deposit
Authors: Su Yi , Wang Jingyi , Gates Ian 
Published: June 2013

Abstract
It has been shown that the performance of a Steam-Assisted Gravity Drainage (SAGD) well pair is affected by its orientation and position within a point bar. In typical commercial operations, multiple wellpairs, usually arranged parallel to each other, are arranged in pads within oil sands reservoirs. Thus, the overall performance of the recovery process in a point bar is not that of a single well pair but reflected by oil accumulation differences, interactions between well pairs (pressure and fluid flow), and how the well pairs interact with the structure and geometry of the point bar including the arrangement of inclined heterolithic strata relative to the SAGD well pairs. This research describes how the point bar structure impacts the performance of a pad of SAGD wellpairs and the impact of pad orientation on performance of the pad. The results show that the performance of well pairs in a SAGD pad are affected by the orientation of the pad within the point bar. Also, the results show that the variability of the performance of the well pairs within the pad is large and thus, single well pair models do not provide sufficient analysis of process performance due to the heterogeneity of the point bar. In other words, pad-scale models are required for recovery process evaluation and design.
Benefits of Passive Inflow Control Devices in a SAGD Completion
Authors: Banerjee Sudiptya , Abdelfattah Tarik , Nguyen Hang 
Published: June 2013

Abstract
Passive inflow control devices (PICDs) have been in use for decades as a tool to manage both frictional effects within the completion system and reservoir heterogeneities that result in an unbalanced injection or production profile. These tools provide an additional pressure drop at select points along a well lateral, evening the distributed flow profile and maximizing economic recovery of oil and gas. Conventional applications of PICDs have become increasingly well understood, yet novel uses still exist, such as the use of PICDs in steam-assisted gravity drainage (SAGD) environments. The SAGD well is characterized by a number of challenges, including poor development of the steam chamber, low reservoir pressure, uneven oil production, and contrasting reservoir permeability. In this paper a typical Albertan SAGD environment is considered against known PICD behavior to quantify the economic benefits of PICD use in the SAGD well pair. Furthermore, the specific benefits of hybrid-geometry autonomous PICDs are highlighted for use in the production well, focusing on possible "steam trap" effects with this geometry. Lessons learned regarding PICD simulation in a thermal environment are shared, outlining a suggested workflow for future modeling work.
Optimization of SAGD Wind-down and Blow-down for Athabasca Oil Sands
Authors: Gu Fagang , Chan Mark , Rismyhr Oddmund , Kjosavik Arnfinn 
Published: June 2013

Abstract
Athabasca is the largest resource accumulation among three major Canadian oil sands reservoirs. Through more than twenty years of research and studies, Steam Assist Gravity Drainage (SAGD) has been proven as an economic viable commercial method to develop Athabasca oil sands. However, because very few of industrial SAGD projects have matured to date, Wind-Down (WD) and Blow-Down (BD) operation strategies are not well understood and more research and study efforts are needed.
In this paper the beginning time and gas injection and production rates in WD and BD with pure methane are optimized for an Athabasca oil sands reservoir with numerical simulation. A simplified economic method and assumptions for optimization are presented and applied in this study. Six type wells are selected to capture the complexity of geological architecture (including pay thickness, and permeability and porosity heterogeneities) and fluid characteristics (thief zones) of the investigated reservoir. The optimization is based on the net values of WD and BD with 2D layer cake simulation models. The sensitivity of the net values to gas and bitumen prices is also analyzed. The strategies to optimize WD and BD for compartment areas or full fields are explored in this paper. For the areas without geomodels, a weighting method is proposed and applied. For areas with geomodels single model simulation is recommended if the areas are not large while the type well/pad methodology is suggested if the compartment areas or full fields are too large to simulate with one model.
The results of this study indicate that understanding reservoir geology and optimizing WD beginning time are important and necessary to have positive WD economic values. In some cases compromise has to be made in optimization simulation due to the complexity of reservoir, availability of model and limitation of resources, and a practical optimization method with proper simplifications have to be taken. With the optimized WD and BD operation and management strategies the economy of SAGD projects can be improved significantly.
Simulation Analysis of Steam-Based EOR Using MultiObjects Grosmont Models
Authors: Ezeuko Cosmos C. , Gates Ian D. 
Published: June 2013

Abstract
Carbonates contain more than 50% of the world's known hydrocarbon resources. Although natural fractures are a common feature in carbonates and they can improve primary production from tight matrix carbonates, they pose a unique challenge for enhanced oil recovery (EOR) from heavy oil and bitumen (HOB) carbonates. The current focus on ‘energy mix’ to sustain the world energy demand has once again put HOB carbonates in global spotlight. Among the known HOB carbonate reservoirs globally, the Grosmont carbonate in Northern Alberta contains the largest original in-place HOB (~406.5 billion barrels). However, the Grosmont carbonate poses the greatest development challenge of all other known HOB carbonates due to its petrophysical complexity. We recently published our progress towards developing a methodology for characterizing the Grosmont carbonate that is suitable for direct reservoir simulation. The objective of the current paper is to assess the performances of different steam-based EOR recovery technologies using multiobject reservoir models of the Grosmont. Our results show that simulations on appropriate reservoir models representative of the most hydraulically active objects produce a good account of heat and fluid flow in complex carbonates. Cyclic steam stimulation (CSS) in this paper describes steam injection below fracture pressure and can therefore be related to what has recently been presented in the literature as cyclic single well steam-assisted gravity drainage.
Integrating the Key Learnings from Laboratory, Simulation, and Field Tests to Assess the Potential for Solvent Assisted - Steam Assisted Gravity Drainage
Authors: Dickson Jasper L. , Dittaro Larry M. , Boone Thomas J 
Published: June 2013

Abstract
ExxonMobil and its Canadian affiliate, Imperial Oil Resources, are actively developing the next generation of solvent-aided and solvent-dominated heavy oil recovery processes. While these new recovery processes possess multiple environmental and technical advantages relative to traditional heavy oil recovery processes, there are a variety of challenges that must be addressed and overcome before commercial application. One especially promising technology is the Solvent Assisted – Steam Assisted Gravity Drainage (SA-SAGD) process. In the SA-SAGD process, a light hydrocarbon solvent (diluent) is injected along with dry steam in a dual horizontal well SAGD configuration.
An integrated research program has been implemented in order to progress the SA-SAGD technology from the laboratory to the field and to better quantify the benefits of SA-SAGD over SAGD. This integrated research program includes fundamental laboratory work, advanced numerical simulation studies, scaled physical laboratory models, and a two well-pair field pilot. In this paper, we review the scope, technical challenges, and key learnings from the laboratory, numerical modeling efforts, and the field pilot. Each individual component of the research program is important and provides unique and useful information concerning the SA-SAGD process. Given the technical and economic challenges of solvent-assisted thermal heavy-oil processes, these types of fully integrated research programs are essential in order to successfully progress new technologies from the laboratory to the pilot scale and ultimately to the commercial scale. Ultimately, the program is targeted at developing reliable commercial predictive capabilities that have been validated against both laboratory and field data, for application to a wide range of heavy oil reservoirs, operating conditions, and development plans.
Key Learnings from a Simulation Study of a Solvent-Assisted SAGD Pilot at Cold Lake
Authors: Dickson Jasper L. , Subramanian Ganesan , Shah Prateek , Otahal Joan M. , Dittaro Larry M. , Jaafar Ali E. , Yerian Jeffrey A. 
Published: June 2013

Abstract
ExxonMobil and Imperial Oil Resources (IOR) are conducting a Solvent Assisted - Steam Assisted Gravity Drainage (SA - SAGD) experimental pilot at Cold Lake in the Clearwater formation. In this SA-SAGD pilot, up to 20% by volume of a hydrocarbon solvent (diluent) has been injected along with dry steam in a dual horizontal well SAGD configuration. The primary objective of the pilot was to quantify the impact of solvent addition on bitumen production and steam-oil ratio (SOR). Key surveillance data collected during the pilot include production/injection rates (oil, water, and solvent), production/injection pressures, horizontal well temperatures, observation well temperatures, saturation logs, and time-lapse 3D seismic surveys.
The objective of this paper is to discuss the modeling efforts that were completed in order to interpret the initial results of the pilot. Specifically, this paper will address (1) the construction of a detailed 3D geologic model and the corresponding flow simulation model and (2) the history-matching results. The geologic model incorporates information from 3D seismic surveys as well as core and log data from the pilot observation wells. Using the geologic model and the field production data, the SA-SAGD process was modeled using a thermal simulator. An acceptable match to the total hydrocarbon production rate, injection pressure, and SOR was achieved through a minor adjustment to the model permeability.
The completed simulation studies are invaluable in increasing our understanding of the key parameters that control flow behavior in the SA-SAGD process. Ultimately, these learnings will be used by ExxonMobil and Imperial Oil Resources to optimize the process and make decisions related to full-field commercial deployment of the SA-SAGD recovery process.
A New Approach for Designing Steam Splitters and Inflow Control Devices in Steam Assisted Gravity Drainage
Authors: Kyanpour Mohammad , Chen Zhangxing 
Published: June 2013

Abstract
The classical SAGD involves drilling wells in parallel horizontal pairs. Steam is injected into the upper well (injector) to heat the reservoir and mobilize bitumen so that it drains to the lower well (producer) and can be lifted to the surface. In this process, steam distribution in the injector and a sustainable liquid level above the producer are key to achieve steam chamber conformance. The completion designs of these wells are critical in order to achieve optimal bitumen recovery and steam chamber development.
Two common tools in SAGD wellbore completions are Steam Splitters and Inflow Control Devices. The Steam splitters are used to customize steam distribution in the injector. The Inflow Control Devices are used in the producer to develop a uniform inflow along the horizontal wellbore.
This paper presents a method for determining the size and position of Steam Splitters and Inflow Control Devices. This method can be used for both simple and complex reservoirs containing heterogeneous geology and hydraulic barriers and baffles.
Rheological Assessment of the Elasticity of Polymers for Enhanced Heavy Oil Recovery
Authors: Wilton Ryan R. , Torabi Farshid 
Published: June 2013

Abstract
More recently polymer flooding recovery processes are becoming increasingly attractive due to the improvements in polymer manufacturing, hydration and implementation successes worldwide. This is especially true in the application of polymer for enhancing heavy oil recovery. It has been suggested that the elastic nature of the polymer is equally important to the viscous properties.
In the present study, a specialized rheometer was used to determine the viscoelastic properties of both hydrolyzed polyacrylamides (HPAM) and hydrophobically associating polyacrylamides (HAP) used in heavy enhanced oil recovery (EOR) processes. The rheometer has the capability to measure rheological properties in porous capillary plugs providing a more representative picture of non-Newtonian fluid flow in reservoirs. The rheological parameters were determined as influenced by polymer type, concentration, molecular weight, hydrophobicity, salinity and temperature. Increases in elastic tendencies were observed as a function of the first four; however, salinity and temperature were found to have a slightly negative effect. A medium density, hydrophobic polymer showed an earlier onset of elastic contribution at in-depth reservoir shear rates as determined by its Weissenberg number. For heavy oil reservoirs utilizing higher polymer concentrations, the viscoelastic properties of a polymer system should be evaluated in the screening process.
Recent studies suggest that viscoelastic polymers can reduce the residual oil saturation below that to waterflood with two different plausible mechanisms at play, depending whether the media is water- or oil-wet. However, in both theories, polymer elasticity is believed to be the dominant force that contributes to the additional reduction in oil saturation. Aside from measuring the elasticity directly, other parameters that quantify a polymer's elastic potential are its relaxation time and Weissenberg number; therefore, the change in these parameters with respect to dynamic shear rate or flow velocity can be further useful for screening purposes.