bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrating Nuclear Energy to Oilfield Operations -- Two Case Studies
Authors: Robertson Eric P. , Nelson Lee O. , McKellar Michael G. , Gandrik Anastasia , Patterson Mike 
Published: November 2011

Abstract
Fossil fuel resources that require large energy inputs for extraction, such as the Canadian oil sands and the Green River oil shale resource in the western USA, could benefit from the use of nuclear power instead of power generated by natural gas combustion. This paper discusses the technical and economic aspects of integrating nuclear energy with oil sands operations and the development of oil shale resources. A high temperature gas-cooled reactor (HTGR) that produces heat in the form of high pressure steam (no electricity production) was selected as the nuclear power source for both fossil fuel resources. Both cases were based on 50,000 bbl/day output. The oil sands case was a steam-assisted, gravity-drainage (SAGD) operation located in the Canadian oil sands belt. The oil shale development was an in-situ oil shale retorting operation located in western Colorado, USA. The technical feasibility of the integrating nuclear power was assessed. Preliminary economic analyses of each case were evaluated using a discounted cash flow, rate of return approach.
Integrating an HTGR to both the SAGD oil sands operation and the oil shale development was found to be technically feasible for both cases. In the oil sands case, integrating an HTGR eliminated natural gas combustion and associated CO2 emissions, although there were still some emissions associated with imported electrical power. In the in situ oil shale case, integrating an HTGR reduced CO2 emissions by 88% and increased natural gas production by over 400%. Economic analyses included parametric evaluations on taxes imposed on CO2 emissions, royalty rates, capital costs, etc. The magnitude of the tax on CO2 emissions was found to have a major impact on the economic results of the cases considered.
As the world moves toward limiting CO2 emissions, integrating non-CO2-emitting energy sources to the development of energy-intense fossil fuel resources is becoming increasingly important. This paper attempts to reduce the barriers that have traditionally separated fossil fuel development and application of nuclear power and to promote serious discussion of ideas about hybrid energy systems.
New Ways of Removing Cyclic Borehole Noise from Low- and High- Resolution LWD Images and Its Impact on Image Interpretation
Authors: Sugiura Junichi , Lee Rick 
Published: November 2011

Abstract
The use of logging-while-drilling (LWD) imaging tools in real-time decision making and post-drilling analysis has become commonplace. However, image noise and processing errors due to the inherent measurement physics can propagate errors and thus complicate interpretation of open-hole log data and images. For example, the standard density images tend to amplify image noise from small borehole irregularities. Among different borehole irregularities, spiraling is known to occur more frequently with conventional rotary assemblies, steerable motor assemblies, and rotary steerable assemblies. When the cyclic noise amplitude from spiraling becomes large relative to the measurement of the primary interest, it grossly affects measurement accuracy of bulk density, photoelectric, and neutron porosity.
This paper shows novel methods to remove cyclic noise from formation evaluation (FE) images by applying frequency-domain filtering. Although the initial attempt of fast Fourier transforms1 illustrates the straightforward concept, it is seldom used due to implementation issues requiring interactive filter design and intensive operator intervention. Recently, a new method2 has been designed to improve the filtering process. Additionally, the new adoptive filter designs automate the cyclic noise removal process from the FE images. Stand-alone software has been developed to process the entire image logs from one well, without human supervision. The software adoptively modifies the filter behavior as borehole oscillation noise characteristics change with formation, drilling assemblies, hole inclination, and depth.
To quantitatively examine its validity, the algorithm is then applied to various field data, not only on low-resolution density images but also on higher-resolution density images. The new algorithm has been proved by bringing considerable improvement to the image quality without any artificial interruptions. The rugosity effect is significantly reduced, and the apparent resolution of bed boundary features increased.
Furthermore, comparative field examples illustrate the improvement in image feature extraction. This new method is critical, for example, for small fracture detection and for accurate dip analysis in irregular boreholes. This new method is not only effectively used for density images but also applicable to any other borehole images, such as resistivity and ultrasonic images.
Horn River Basin: A Study of the Behavior of Frac Barriers in a Thick Shale Package Using the Integration of Microseismic, Geomechanics and Log Analysis
Authors: Beaudoin Bill , Allison Jeff , Khalid Salman , Faurschou Ken 
Published: November 2011

Abstract
Horn River Group (HRG) shales are prime exploration targets. The shales form a 200m thick package of over-pressured, organic rich, siliceous mudrocks found at drilling depths between 2400–2700m. The gross thickness of the shale interval and the observed frac barriers within the shale package present a challenge for maximizing the stimulated rock volume when completing wells. Within Devon Canada, an exploration program was designed to evaluate reservoir complexity and heterogeneity, the ultimate goal being to optimize horizontal, vertical and lateral well placement while balancing recovery factor and capital costs.
Core and log data from vertical wells were analyzed to target optimal horizontal drilling zones for hydraulic fracture initiation and ease of drilling. Geomechanical log analysis supports the observation made from microseismic data that frac height growth through the frac barriers in the shale package happens preferentially depending upon the direction from which the fracture was initiated.
Chemical Process for Improved Oil Recovery From Bakken Shale
Authors: Shuler Patrick , Tang Hongxin , Lu Zayne , Tang Yongchun 
Published: November 2011

Abstract
There is a new chemical improved oil recovery (IOR) process for Bakken reservoirs. In this concept a custom surfactant agent may be incorporated into standard hydraulic fracturing treatments for the Bakken to increase oil recovery. These are reservoirs from the Late Devonian to Early Mississippian age occupying about 200,000 square miles (520,000 km2) of the subsurface of the Williston Basin, covering parts of Montana, North Dakota, and Saskatchewan. The rock formation consists of three members: Lower shale, Middle dolostone/siltstone, and Upper shale. The shales were deposited in relatively deep marine conditions, and the dolostone/siltstone was deposited as a coastal carbonate during a time of shallower water. The Middle member is the principal oil reservoir, roughly two miles (3.2 km) below the surface. Both the Lower and Upper members are organic-rich marine shales.
The oil in place in the Bakken shale play is very large, with an April 2008 USGS report estimating the amount of technically recoverable oil in the Bakken Formation at 3.0 to 4.3 billion barrels. Production from the Bakken has been limited in the past, but now has become a very active area of development with the widespread advent of drilling horizontal wells and large-volume hydraulic fracturing treatments. One key to the economic production rates of oil from these formations is to create an extensive well-connected fracture system.
Laboratory experiments demonstrate that specialized surfactant formulations will interact with this mixed- to oil-wet low permeability Middle member to produce more oil. Specifically, including such a surfactant chemical formulation in an aqueous phase (e.g. hydraulic fracturing fluids) will promote the spontaneous imbibition of this fluid into the tight matrix and microfractures containing high oil saturation. This promotes expulsion of oil otherwise trapped to migrate into the fracture system and then be produced into the wellbore. Thus including an appropriate surfactant in frac fluids or in other aqueous-based treatment fluids can produce additional oil.
Case Study: Modeling the Phase Behavior of Solvent Diluted Bitumen
Authors: Agrawal P. , Schoeggl F. F. , Satyro M. A. , Yarranton H. W. 
Published: November 2011

Abstract
The design of solvent-based and solvent assisted heavy oil recovery processes requires accurate predictions of phase behavior as straightforward as saturation pressures and as potentially complex as vapour-liquid-liquid equilibria and asphaltene precipitation. In this case study, saturation pressures of dead and live bitumen were measured in a Jefri PVT cell at different concentrations of a multi-component solvent at temperatures from 20 to 180°C. Saturation pressures and the onset of asphaltene precipitation were also measured for the bitumen diluted with n-pentane. The onset of precipitation was determined by titrating the bitumen with pentane and periodically circulating the mixture past a high pressure microscope.
The data were modeled with the Advanced Peng-Robinson equation of state (APR EoS). The maltene fraction of the bitumen was characterized into pseudo-components based on extrapolated distillation data. The asphaltenes were characterized based on a Gamma distribution of the molecular weights of self-associated asphaltenes. The APR EoS was tuned to match the saturation pressures by adjusting the binary interaction parameter between the solvent and the pseudo-components via a correlation based on critical temperatures. Rather than adjusting the interaction parameters for each pair of components, only the exponent in the correlation was adjusted. The role of mixing rules in correctly predicting the onset and amount of asphaltene precipitation is discussed.
Numerical Simulation of SAGD with Vertical Slimholes
Authors: Chang J. , Ivory J. , Tunney C. 
Published: November 2011

Abstract
Steam assisted gravity drainage is the primary in-situ recovery method for bitumen from the large Athabasca deposit in Alberta, Canada. SAGD field operations encounter a significant decrease in production performance when low permeability shale barriers are present in the formation. These layers can reduce SAGD performance and impede the growth of the steam chamber. They also significantly limit the percentage of the deposit where bitumen can be economically recovered with SAGD. The concept of drilling vertical slimholes to create flow paths through barriers was conceived and investigated at Alberta Innovates - Technology Futures (formerly the Alberta Research Council). Use of slimholes has the potential to significantly increase the amount of recoverable bitumen (reserves) and the rate at which it is produced during SAGD. For shallow reservoirs, the slimholes could be drilled from the surface at relatively low cost.
2-D and 3-D field scale numerical simulations were performed using reservoir properties and operating conditions that were based on published information for the MacKay River SAGD operation in the Athabasca deposit. The reservoir depth was 135 m, the initial pressure 500 kPaa, the initial temperature 7.5 °C, and the initial oil saturation 0.8. The simulations explored the impact of vertical slimholes, which were 7 m laterally offset from the horizontal well pair (Figure 1), on reservoirs with and without shale layers or shale lenses. The effect on SAGD performance of slimhole cross-section (25 cm × 25 cm or 50 cm × 50 cm) and distance between slimholes (12 m or 24 m in the direction parallel to the well pair was investigated). The effect of reservoir and slimhole permeability and the impact of horizontal slimholes from the injector or producer were also explored.
The slimholes were represented by high permeability vertical channels using refined grids. Counter-current flow of gas and liquid through the slimholes was represented by adjusting the relative permeability in the slimholes.
For a reservoir, with a continuous shale layer, SAGD performance was improved by vertical slimholes due to the recovery of previously inaccessible oil from above the shale layer where a secondary steam chamber was formed.
A Parametric Simulation Study for Solvent Co-injection Process in Bitumen Deposits
Authors: Yazdani A. , Alvestad J. , Kjonsvik D. , Gilje E. , Kowalewski E. 
Published: November 2011

Abstract
In situ extraction of ultra viscous deposits from the vast bitumen resources in western Alberta requires significant water and energy usage which consequently lead to green house gas emissions. Currently proven steam-based recovery schemes include Cyclic Steam Stimulation, Steamflooding, and Steam Assisted Gravity Drainage (SAGD) processes, which are accompanied by many economical and environmental challenges. Co-injection of solvent with steam is a technology that has the potential to improve the efficiency of steam processes as well as reduce the energy use and CO2 emissions.
In recent years, researchers and industry have attempted to further develop the process by conducting fundamental research as well as field pilot trials with varying degrees of success. However, the current level of understanding of the process and knowledge around the fundamental physics and mechanisms involved are not fully satisfactory.
In this paper, a parametric simulation study was performed to address the key aspects of the solvent co-injection (SCI) process that contribute to further understanding and development of the process. Simulation observations were verified with experimental evidence where available to support the results and conclusions. Effects of several operational and geological parameters were evaluated on the performance of the SCI process and the relative performance benefits were assessed over normal SAGD operations. These parameters included solvent type, solvent concentration, initial solution gas-oil ratio, relative permeability curves, pay thickness, and presence of a low quality top layer.
The results revealed that the optimum solvent should not only be chosen on the basis of mobility improvement capability, but should also consider other operational, phase and flow behavioral and/or geological conditions that are set or present. Higher concentrations of solvents showed more energy saving upsides than rate acceleration benefits. It was also observed that the reservoir steam intake rate is still likely to be the prime performance indicator of the SCI process. In addition, it was found that the potential exists with the SCI process for accessing more resources, particularly below the producer level. Furthermore, steam trap control on the producer seems to be problematic when utilized for SCI simulation. With the current well control capacity of simulators, a higher degree of subcool is likely to be needed to avoid live vapor phase production from the producer.
Experimental and Analytical Modeling of Gravity Drainage Dominated Heavy-Oil Recovery Under Non-Isothermal Conditions: A Microscale Approach
Authors: Arguelles-Vivas F. J. , Babadagli T. 
Published: November 2011

Abstract
Steam assisted gravity drainage (SAGD) is a well-known example of a non-isothermal gravity dominated recovery application. It is commonly observed that field scale applications of this process yield less recovery than estimated. This requires in-depth analysis of the problem at the pore scale to account for the residual oil saturation in the swept zone.
It is still uncertain to what extent pore scale mechanisms, such as the counter and co-current nature of multiphase flow, the trapping mechanism and the distribution of phases, the formation and flow of emulsions, and heat transfer mechanisms affect the process of non-isothermal gravity drainage dominated heavy-oil recovery. Alteration of wettability due to phase change under steam heating and how wettability interacts with spreading coefficients are still enigmatic.
In this paper, we used a single capillary tube to mimic an elementary volume in the swept area during gravity dominated displacement under non-isothermal applications. We carried out two-phase (air-oil) and three phase (air-oil-initial water saturation) flow displacements in a capillary tube under isothermal and non-isothermal conditions, varying the air injection rate and the capillary properties. Detailed visualization experiments were carried out to analyze: (1) The effects of oil viscosity, wettability and the spreading coefficient on isothermal and non-isothermal displacement, (2) the interplay among capillary, gravity and viscous (steam injection rates) forces and wettability using different size capillaries, and (3) residual oil saturation and phase distribution in the capillaries (mainly the thicknesses of the wetting and non wetting phases).
The analytical calculations based on the experimental observations (measured displacement rates) suggest that at low capillary numbers, the temperature does not have a significant influence in the residual saturation of processed and crude oil. For heavy crude oil this is true for the capillary numbers less than 0.02. Above this threshold capillary number, the oil recovery (and therefore residual oil saturation) is very sensitive to the capillary number, i.e., the injection rate, interfacial tension, and wettability, and to temperature.
Unlocking Thin Beds Potential: Gas Identification Through Downhole Fluid Analysis
Authors: Loi D. , Mazzoni S. , Gigliotti M. , Baio C. , Borghi M. , Baldini D. , Italiano F. , Cantini S. 
Published: November 2011

Abstract
Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s. The gas is produced from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in indentifying gas bearing zones. This paper proposes a critical review of existing thin beds evaluation techniques and shows a successful case history using wireline formation testing technology.
While gas identification in metric reservoirs can be achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less. Even the most advanced petrophysical logging tools struggle in providing discrimination of gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds often overpressurized and pressures are supercharged due to low mobility.
A new wireline formation testing approach for thin beds to discriminate gas from water zones was proposed, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. Twelve stations in thin beds were attempted, all resulted representative in terms of fluid identification and pressure measurement. Productivity forecast of the tested intervals was also provided using as input pressures and permeabilities derived from dual packer tests.
The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well testings, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves.
Several gas fields today producing from metric reservoirs will be revisited in the very near future in order to start production from thin beds, until now untouched. The wireline dual packer approach described in this paper, along with enhancement of petrophysical logs applications, will certainly play a key role in optimal exploitation of thin beds gas reserves.
Experimental Study of Air Injection in SAGD Chamber
Authors: Rahnema H. , Barrufet M. , Mamora D. 
Published: November 2011

Abstract
Steam Assisted Gravity Drainage (SAGD) is a successful method for recovering bitumen and heavy oil that is widely used in Alberta, Canada. However as the SAGD chamber fully develops (mature chamber), the oil production rate starts to decline and the steam oil ratio (SOR) to increase, directly affecting the economic viability of the process at this stage. Air injection after SAGD is one potential option to recover residual oil inside mature SAGD chambers, and to avoid having steam migration form adjacent SAGD patterns.
In this paper, a detailed laboratory experiment is presented in order to analyze the feasibility of in-situ combustion after an SAGD process. A 3D laboratory model was designed and constructed. The combustion cell was fitted with 48 thermocouples. A horizontal pair well is placed at the bottom of the model with interwell spacing of 3 cm. The SAGD chamber occupies 26% of the model. The first 15 cm of the injection well is preheated using an electric igniter. Enriched air is used for establishing the combustion chamber. After ignition, the combustion front develops near the injection side and progresses forward while laterally limited inside SAGD chamber boundaries. Flue gases and hot oil are produced through the bottom horizontal well. A maximum temperature of 617°C was recorded, with cumulative oil recovery of 12% original oil in place (OOIP). Post experiment analysis of the sand pack shows that, besides sweeping the residual oil in the SAGD chamber, the combustion process created a hard coke shell around the chamber, which isolated the steam chamber from the surrounding media.