bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigating the Effect of Steam, CO2, and Surfactant on the Recovery of Heavy Oil Reservoirs
Authors: Tian Shubao , He Shunli , Qu Li 
Published: October 2008

Abstract
In this paper, the complicated displacement mechanisms of injection of CO2, surfactant and steam into heavy oil reservoirs are evaluated using a laboratory physical model and a numerical simulation model. There are four different recovery scenarios examined, which include steam-only injection, steam injection with CO2, steam injection with surfactant and steam injection with CO2 and surfactant. The incremental recoveries of different scenarios are compared and analyzed. The effect of CO2 dissolution in oil and water, variation of properties of CO2-oil phase equilibrium and CO2-water phase equilibrium, variation of viscosity, oil volume and interfacial tension (IFT) during the recovery process are investigated. The expansion of steam and CO2 front is also examined. A field application case of a horizontal well in a heavy oil reservoir in Shengli Oilfield, China is studied. The actual dynamic performance of the horizontal well with cyclic injection with steam, CO2 and surfactant is analyzed and the injection parameters are optimized. The results show that in spite of immiscible drive of CO2, CO2 dissolution in oil helps to improve flow performance of heavy oil. At the same time, while CO2 is simultaneously injected with steam, it decreases the temperature of steam front to some extent compared with steam injection only, which has an effect on the expansion of steam chamber. Viscosity reduction, swelling and IFT reduction play important roles in improving recovery factor of heavy oil reservoirs. K values of CO2-oil and CO2-water phase equilibrium vary with reservoir pressure and temperature, which have an effect on displacement process. In laboratory model the oil recovery of the simultaneous injection of steam, CO2 and surfactant is higher than that of others. In the field application case the optimal design of injection parameters helps achieve the highest recovery.
Adaptive Implicit Method for Thermal Compositional Reservoir Simulation
Authors: Agarwal Anshul , Tchelepi Hamdi A. 
Published: October 2008

Abstract
Thermal compositional reservoir simulation with a large number of hydrocarbon components is computationally intensive, especially as the number of variables treated implicitly increases. The Fully IMplicit method (FIM) treats all the variables implicitly; it is unconditionally stable (even with possibly large timesteps), but it is computationally expensive. In contrast, the IMPEST (IMplicit Pressure, Explicit Saturations and Temperature) method is computationally inexpensive, but only conditionally stable; the allowable stable timestep of IMPEST for large-scale heterogeneous models may be extremely small. AIM (Adaptive IMplicit method) offers a balance between FIM and IMPEST by treating a subset of the primary variables implicitly.
The challenge with AIM is to find robust and sharp stability criteria that can be used to choose an optimal timestep size and devise an efficient switching algorithm to dynamically label variables in grid blocks implicit or explicit. The switching algorithm aims to maximize the timestep size at which a stable solution for explicit saturation, temperature, and compositions in a grid block is guaranteed. In this paper we apply the thermal stability criteria to both the traditional percentage-based switching algorithm as well as a variable-based switching algorithm. This Thermal AIM (TAIM) framework was implemented in Stanford's General Purpose Research Simulator (GPRS).
The TAIM stability criteria are obtained using von Neumann approach. The derivation of the criteria is done using a comprehensive linear stability analysis that takes into account complex physics including mass and heat convection, heat conduction, capillary mixing and compressibility. We found the stability criteria to be sharp, i.e. small violation of the criteria leads to unstable solutions. The presence of heat conduction does not impose restrictive stability conditions on time steps due to the explicit treatment of temperature. Variable-based switching leads to a more efficient TAIM solution as compared to a percentage-based strategy.
Quest to Validate and Define Performance for the High Volume Metallic Stator PCP at 250°C
Authors: Noonan S. G. , Klaczek W. , Piers K. , Seince L. , Jahn S. 
Published: October 2008

Abstract
ConocoPhillips has been on a quest to find a high volume artificial lift system that will operate reliably in a 250°C (482°F) downhole environment, which exists in certain SAGD applications. This presented two problems: 1) there were no commercially available technologies for such a high temperature; and 2) there were no facilities capable of testing these systems.
This paper describes the complexity of building and operating a high temperature flow loop rated for 250°C, and the lessons learned while upgrading an existing flow loop, from the initial design through the final commissioning phases. The paper also describes the issues encountered with the first artificial lift system tested at 250°C, which was a metallic stator progressing cavity pump system, rated for 1100 m3/d (6919 bpd) at 500 rpm.
In the end, the test program not only served to validate and define the pump's performance, but also provided valuable lessons on the completion configuration and operational procedures.
Reduction of Light Oil Usage as Power Fluid for Jet Pumping in Deep Heavy Oil Reservoirs
Authors: Chen Shengnan , Li Heng , Yang Daoyong , Zhang Qi , He Jun 
Published: October 2008

Abstract
Jet pumping has been considered as an efficient artificial lifting technique for deep oil production due to its simplicity and lack of moving parts. If light oil is used as power fluid, jet pumping becomes one of the preferred artificial lift methods for the deep-heavy-oil reservoirs by dramatically reducing both viscosity of the reservoir fluid and the pressure loss along the production string. In practice, the amount of light oil required as the power fluid can be as high as three times of the reservoir fluid, among which only a small portion of the light oil is actually needed for viscosity reduction. In this paper, a novel technique has been developed and successfully applied to significantly reduce the amount of light oil usage in a deep-heavy-oil reservoir. More specifically, two approaches are developed and compared. As for Approach A, the oil well is produced with jet pumping driven by light oil first, and then the produced fluid is reinjected into the well as the power fluid. This process keeps circulating until viscosity of the produced fluid is too high to be utilized for jet pumping. As for Approach B, partial produced fluid is combined with the light oil at any reasonable ratios, and subsequently the produced fluid-light oil mixture is reinjected into the well as the power fluid. In the latter approach, viscosity of the mixture keeps increasing and will reach its equilibrium value in a few days, and thus, stable production will be achieved as well. Theoretic models are developed to determine the viscosity of the power fluid for each circulation and the maximum cycle number for the former approach as well as the equilibrium viscosity of the mixed power fluid and the optimum ratio of light oil to the produced fluid-light oil mixture for the latter approach. Field applications show that the reservoir fluid produced from deep heavy oil wells is increased by three times and that the amount of light oil can be reduced by more than 60% for either approach.
Mitigating in Situ Oil Sands Carbon Costs
Authors: Theriault David J. , Peterson Jeff , Heinrichs Harvey 
Published: October 2008

Abstract
You've heard the direction, you've seen the papers, and you've read the publications. The Government of Canada's March 2008 "Turning The Corner - Taking Action to Fight Climate Change" report has set the foundation for CO2 regulations which "start tough and get tougher". The "Toughest" requirements are set for new oil sands plants and coal-fired power plants that come into operation in 2012, or later. The public and legal arena is also impacted by how oil sands carbon emissions are addressed. The Report on Business, March 6, 2008, reported; "a federal court judge … found the approval of Imperial Oil Ltd's $8 billion oil sands mine insufficient on climate change and green house gas emissions." The Conference Board of Canada Carbon Disclosure Project Report 2007 has also stated that "Alberta's GHG reduction legislation will add approximately $0.18/bbl in additional operating costs for a typical integrated oil-sands mining project, and $0.22/bbl for a steam-assisted gravity drainage project." These and other factors have changed the landscape for oil sands development.
A review of the political, social, and regulatory pressures and obligations for the in situ oil sands industry to reduce its oil sands carbon foot print will be provided. This paper will discuss Laricina's insights and views on the carbon challenge, describe initiatives Laricina is taking to manage these imperatives and outline the challenges the overall industry is facing. The objective of this paper is to spur dialogue and collaboration by the oil sands industry in an effort to evolve and advance the knowledge and understanding of the impacts this important issue has on our business. This paper will also attempt to describe the dimensions of the carbon problem, point out the experience base our industry has to contribute to a solution, review the parameters to demonstrate CO2 or GHG's containment and storage, touch on the state of regulatory and policy issues, and try to scope out a progression to technical and economic success.
Providing Floating Capabilities in Latest-Generation Sand Screens
Authors: Bowen Eddie G. , Coronado Martin P. 
Published: October 2008

Abstract
Industry interest is turning to alternative means of production for the massive reserves located in the Bitumen Region of Canada's Tar Sands. Currently, the region has over 100 installations of sand screens/slotted liners in both injection legs and production legs using Steam-Assisted Gravity Drainage (SAGD) technology. Due to the sensitive nature of the environment, multiple wells must be drilled from a single pad. With the average depths of these wells between 200 and 400 m and lateral lengths between 800 and 1,000 m, a floating sand screen provides assurance that the sand screen will reach the desired depths.
The most typical method of floating the sand screen to bottom uses paraffin to plug the flow access of the screen during installation. In shallow depth wells, the paraffin must be capable of handling differential pressure between the annulus and inside diameter of the screen or liner assembly equivalent to the hydrostatic pressure and any surge pressures encountered during the installation process. The use of paraffin to plug the sand screens currently limits the differential capability to less than 200 psi.
A new technology has been developed that allows for sand screen installations without relying on paraffin wax to withstand differential pressure. This new technology uses a hydro-mechanical valving system incorporated into the screen design to temporarily close off the screen while being run in the hole.
This paper will describe how this technology can provide a reliable, time-saving solution for SAGD installations when floating sand control screens in the hole is required. This solution provides a unique alternative to the methods currently being used to install sand screens with SAGD technology in the rapidly growing Canadian market for bitumen recovery.
Experimental Study of Heavy Oil-Water Flow Structure Effects on Relative Permeabilities in a Fracture Filled with Heavy Oil
Authors: Shad Saeed , Gates Ian D. , Maini Brij B. 
Published: October 2008

Abstract
Fracture dominated two-phase flow is important not only for naturally fractured petroleum reservoirs but also for underground disposal of radioactive waste, geothermal hydrotransport, as well as underground water and aquifer flow. In contrast with gas-liquid flow in a single fracture, the flow of heavy oil and water received rather less attention. In this research an experimental apparatus was built to study the flow of water in presence of heavy oil in a smooth-walled fracture and display the different flow patterns under different flow conditions. Also the relationship between different flow pattern and relative permeability curves in a single fracture was investigated. The results were compared with available relative permeability models such as segregated/lubrication model, viscous coupling model, X (stick) curve model, Corey model and T-C model. The comparison leads to the conclusion that there is high interference between the phases flowing through the fracture. The results show that different phases can flow in both continuous and discontinuous forms. Also studying the flow of oil and water under different flow patterns shows that the oil-water relative permeability is not just a function of the fluid saturations but also the fluid properties and flow pattern within the fracture itself.
How In-Situ Combustion Process Works in a Fractured System: Two-Dimensional, Core and Block Scale Simulation
Authors: Fadaei H. , Quintard M. , Debenest G. , Renard G. , Kamp A. M. 
Published: October 2008

Abstract
Simulation of an in situ combustion process (ISC) was done for a fractured system at core and matrix block scales. The aim of this work was to: 1) To predict the ISC extinction/propagation condition(s), 2) understand the mechanism of oil recovery and provide some guidelines for ISC upscaling for a fractured system. The study was based on a fine grid, single porosity, multi-phase and multi-component simulation using a thermal reservoir simulator. The following results were obtained:
a) Firstly the simulator was validated for 1-D combustion using the corresponding analytical solutions. 2-D 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 the results be independent of grid size. b) ISC in fractured system was feasible under certain conditions: The extinction/propagation of ISC was strongly dependent on the oxygen diffusion coefficient while the matrix permeability played an important role in oil production. c) Effect of each production mechanism was studied separately whenever it was possible. Oil production is governed mainly by gravity drainage and thermal effects; possible pressure gradient generation in the ISC process seems to have a minor effect. d) The nature of ISC at core scale was different between a single block and multiple blocks (oil production rate, saturations distribution, shape of the combustion front). The characteristics of different zones (i.e. combustion, coke, oil) at block scale were studied and some preliminary guidelines for usscaling are presented.
Visualization of Viscous Coupling Effects in Heavy Oil Reservoirs
Authors: Ortiz-Arango J. D. , Kantzas A. 
Published: October 2008

Abstract
Despite the many publications about the production mechanisms of heavy oil reservoirs, there is still no consensus as to what is behind the anomalous production rates observed in some reservoirs in Venezuela and Canada. Many authors attribute the recovery of a much higher fraction of the original oil in place to a special phenomenon associated to the solution-gas drive mechanism, known as "foamy" or "bubbly oil", present in heavy oil reservoirs. However, the "foamy oil" behavior cannot clearly explain the mechanism of the observed oil production rate enhancement.
Considering the physical principles of two-phase flow through porous media, the viscous coupling or momentum transfer between the flowing phases would appear as a hidden driving mechanism to explain the improved oil mobility. The use of capillary models has provided a new insight into the effect of the viscosity ratio on relative permeabilities and the importance of water lubrication in heavy oil-water two-phase flow. However, despite the models predictions show that the viscosity ratio affects the relative permeabilities, especially in systems involving very viscous oil, the lack of experimental results makes it difficult to support the theoretical observations.
As a result of the considerable ambiguity in the literature regarding the viscous coupling effects, the focus of this work is to provide new experimental results on the effect of the viscosity ratio on the oil mobility at the pore scale. Flow visualization experiments are conducted in a 2D etched network micromodel. Observations and measurements are presented.
Risk Assessment for SAGD Well Blowouts
Authors: Worth Darren J. , Crepin Stephan , Alhanati Francisco , Lastiwka Martin 
Published: October 2008

Abstract
A comparative risk assessment was conducted to evaluate the risk associated with a Steam Assisted Gravity Drainage (SAGD) well blowout. The main comparison was between an isolated (double barrier) completion and an open (single barrier) completion used in conjunction with an effective blowout response plan. The target application was a SAGD pilot project in the Orinoco Belt in Venezuela.
The overall approach for the risk assessment included the investigation of the blowout flowing potential of the SAGD wells pair through reservoir modelling, the estimation of the probability of a blowout using fault-tree analysis, and the evaluation of the possible consequences (life safety, environmental and economic) of such blowout using various quantitative consequence models. Details of this approach are discussed in this paper, along with the results specific to the target application.
Results of this work can provide guidance for similar operations where decisions regarding completion options and blowout response plans are required. One key result was that, for this specific SAGD pilot project, a blowout response plan must be able to reduce the blowout duration substantially (from 3 days to 1 day for environmental risk, and from 3 days to 2 hours for economic risk) for the environmental and economical risks associated with a open completion to be comparable to those of an isolated completion.
Investigation of Low Pressure ES-SAGD
Authors: Ivory John , Zheng Rong , Nasr Tawfik , Deng Xiaohui , Beaulieu Gilles , Heck Gord 
Published: October 2008

Abstract
SAGD is a commercially proven technology for Athabasca reservoirs. It produces high oil rates and high ultimate recoveries. Injecting a solvent with the steam can reduce required steam rates and/or improve oil rates and recovery. Oil viscosity is reduced both thermally and by solvent dissolution.
A scaled model experiment was performed at the Alberta Research Council to examine the effectiveness of the Expanding Solvent-SAGD (ES-SAGD) process at a low pressure (1,500 kPa), which was still high enough to allow sufficient drive to transport the produced fluids to the surface at typical Athabasca formation depths. A lower SAGD pressure typically results in reduced oil production as a result of the correspondingly lower steam temperature. However, a lower operating pressure can also result in a reduced SOR because of lower steam density (lower mass of steam required to fill a specific volume of the steam chamber) and also a higher heat of vaporization, which allows more heat to be transferred to the reservoir when a given mass of steam is condensed. At lower pressures, the steam saturation temperature changes more quickly with saturation pressure than it does at higher pressures. Thus, at low pressure, a small reduction in pressure can lead to steam flashing in the producer and create unstable conditions.
This experiment was history matched and then a parametric investigation was performed based on field scale numerical simulations using CMG STARS. The same solvent (gas condensate) and solvent concentration (9.3 volume%) were used in the lab and field scale simulations. The condensate had many components, which were represented in the numerical simulations by four pseudo-solvent components.
2-D and 3-D field scale simulations examined the effect of: operating pressure, injection rate, sub-cool, oil and gas phase diffusion and dispersion, live oil versus dead oil performance, use of pressure drawdown when oil rates have declined, and compared low pressure ES-SAGD to low pressure SAGD.
The simulations indicated that the effects of production pressure, sub-cool, and solvent concentration must be considered simultaneously as they impact each other. At 1,500 kPaa production pressure and 10 °C sub-cool, co-injection of solvent with steam increased the average oil rate by 15% while reducing the SOR as compared to SAGD at the same operating pressure.
Evaluation of SAGD Performance in a Deltaic Environment
Authors: Caplan Mark , Heron Caroline , Sullivan Laura , Herle Emeline , Keith Jesse , Bernal Andrea , Atkinson Ian 
Published: October 2008

Abstract
The depositional setting of the McMurray Formation within the main Athabasca fairway has been extensively studied by industry and is well documented in the literature. Much crown land in this easternmost part of the Athabasca Oil Sands Area (AOSA) is currently being drilled and geologically characterised with the aim of in-situ thermal extraction methods, such as SAGD. Reservoirs in this region consist of tidally-influenced channel sands and open estuarine tidal sand bars. There are, however, new plays being discovered in the northwestern part of the AOSA that represent strikingly different depositional environments. Athabasca Oil Sands Corp. (AOSC) holds extensive oil sands assets in this western region of AOSA, and has discovered thick, good quality bitumen pay within the McMurray Formation.
Depositional environments of the McMurray Formation in this region contrast significantly to those reservoirs located within the main fairway to the east. This paper will describe the depositional environment, the building of a numerical simulation model to represent this reservoir, and the results of simulation studies predicting the performance of SAGD behaviour in this particular depositional setting.