bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of High Oil Viscosity on Slug Liquid Holdup in Horizontal Pipes
Authors: Kora C. , Sarica C. , Zhang H.-Q. , Al-sarkhi A. , Alsafran E. M. 
Published: December 2011

Abstract
In the recent years, the increased consumption of hydrocarbon resources and the decline in discoveries of low viscosity oils increased the importance of high viscosity oils. Significant changes in flow behavior were observed with increasing oil viscosity. Determination of the liquid holdup in the slug body is essential to calculate pressure drop for multiphase flow systems.
An experimental study was performed to investigate the effect of high oil viscosity on slug liquid holdup and liquid film height. 144 tests were carried out in 50.8-mm ID horizontal pipe for different oil viscosities and superficial liquid and gas velocities. Tests were conducted at oil viscosities of 0.587, 0.378, 0.257 and 0.181 Pa-s. Superficial liquid and gas velocities varied from 0.1 to 0.8 m/s and 0.1 to 3.5 m/s, respectively. The experimental measurements were compared with the existing slug liquid holdup model predictions to investigate the performances of these models for high viscosity oil.
The predictions of the Gregory et al. (1978), the Gomez et al. (2000), the Abdul-Majeed (2000), the Al-safran (2009) correlations and the Zhang et al. (2003) mechanistic model were compared with high viscosity data. It was concluded that the slug liquid holdup predictions of these empirical and mechanistic models disagree with measurements especially above a 2 m/s mixture velocity. New slug liquid holdup correlations were developed in this study. The new correlations are expected to improve predictions of slug liquid holdup for high viscosity oil especially at high mixture velocities. No significant effect of high oil viscosity on liquid film holdup was observed within the selected oil viscosity range of this study.
A New Approach to Numerical Simulation of Fluid Flow in Fractured Shale Gas Reservoirs
Authors: Bogachev Kirill , Zhabitsky Yakov , Eydinov Dmtry , Shelkov Vasilii , Robinson Tom 
Published: December 2011

Abstract
This paper presents a novel approach to numerical simulations of hydraulic fractures in dynamic reservoir simulations. The fluid flow in fractures is modeled through a network of virtual perforations created in the model grid blocks intersected by the expected fracture trajectory and directly connected to the fractured well. It is demonstrated that by adjusting the productivity indexes of fracture virtual perforations on each time step, practically any static and dynamic behavior of the fracture and its proppant can be realistically modeled. The crossflow between real and virtual perforations is managed by solving a joint well equation. The algorithm takes into account effects of fracture permeability degradation due to pressure, proppant destruction, or total accumulated liquid flux. When the fracture half-length is greater than the average grid block size, the approach described in this paper provides much more realistic simulations than the conventional skin-factor approach or manual generation of high permeability channels. One of the most important advantages of the proposed method is that it can be robustly used for large full-field models with hundreds of horizontal or vertical wells with large scale hydraulic fracturing.
Pre-Treatment Options for Frac Flow Back Brines: Laboratory and Pilot Plant Testing of Oil Removal Materials
Authors: Platt F. M. , Burnett D. B. , Eboagwu U. M. , Vavra C. J. 
Published: December 2011

Abstract
This paper deals with the need to determine the optimum solution for the removal of hydrocarbons in frac flow back fluids on wells completed in unconventional resource areas. These include wells in the Barnett, Eagleford and Marcellus Shales. Fracture stimulation fluid volumes of up to 14 million gallons per well are becoming common. A significant portion of that water returns to the surface as a contaminated waste. To reduce cost and lower the environmental impact of managing such production, companies are seeking to treat and re-use fluids during development of the field.
This project looked at several methods to remediate the produced hydrocarbons to allow reuse of the fluids in other treatments. Our investigations included testing of removal techniques and the concomitant analytical methodology to use in field operations to ensure proper performance of the technologies. Tests were performed with actual field produced brines with five different filter medias including samples that can be regenerated as an alternative to absorbent materials that require replacement or regeneration to continue operation. Pre-treated fluids were then processed through subsequent membranes and purification to make them suitable for re-use. Results from this work have allowed our program to develop more efficient removal treatments and more reliable analytical methodology providing better field level guidelines for commercial operations.
Improving Fracture Initiation Predictions on Arbitrarily Oriented Wells in Anisotropic Shales
Authors: Prioul Romain , Karpfinger Florian , Deenadayalu Chaitanya , Suarez-Rivera Roberto 
Published: December 2011

Abstract
The hydraulic fracturing stimulation of unconventional shale reservoirs requires the identification of sections along the well with good reservoir and completion quality. Completion quality depends on the poromechanical properties of the reservoir. Shales are known to exhibit anisotropic elastic properties. The elastic anisotropic of shales is of first order as it affects four key geomechanical steps: the in-situ stress field, the stress concentration around the borehole, the failure properties both in tension and compression and the geometry of the hydraulic fracture. Consequently, the initiation pressure of hydraulic fractures at the wellbore predicted by data and models taking into account the anisotropy can be lower or higher by up to 100% as compared to isotropic conditions.
We performed a thorough sensitivity analysis of in-situ stress, material anisotropy and well orientation conditions for different scenarios for far field in-situ stress and near field borehole stress, under isotropic and anisotropic conditions. We consider three scenarios. Scenario-1 where both the far field in-situ stress and the near field borehole stress are computed under isotropic assumption. Scenario-2 where only the far field in-situ stress is computed using anisotropic assumption while keeping the isotropic solution for stress concentration is kept. Scenario-3 where both the far field in-situ stress and the stress concentration take into account the material anisotropy. In addition, for each scenario, we considered three different σH/σh cases. This study shows that the full anisotropic solution or scenario 3 is always the most appropriate one for predicting correct initiation pressures and the pressure is always lower for the anisotropic case. It is clear that the observed effects are magnified by the degree of anisotropy of the rock, i.e. each rock or formation will influence differently the initiation pressure. We conclude that the material anisotropy is affecting the in-situ stress model as well as the stress concentration around the borehole. Both effects need to be considered in order to account for the anisotropy. If the effect of the anisotropy is taken into account, for both the far and the near field, it will be possible to better predict the initiation pressure and better stimulate unconventional reservoirs.
Morphology and Growth of Fractures in Unconventional Reservoirs
Authors: Zhao Nan , McLennan John , Deo Milind 
Published: December 2011

Abstract
Understanding the morphology and growth of hydraulic fractures is essential in the development of unconventional tight gas and shale gas resources. In this paper, we report the use of a computational tool consisting of geologic data representation, geomechanical modeling and multiphase flow simulations to predict reservoir performance. A finite element-based geomechanical module is interfaced with a control-volume finite element discrete-fracture reservoir simulator. The hydraulic fracture geometry is generated by following the fluid injection pathway in the existing fracture network and in the matrix. The permeabilities in the fractures and in the matrix are adjusted dynamically in the simulator based on coupling of the geomechanical and flow attributes. The approach described is applicable to tight gas and shale gas reservoirs. There are over 3700 active wells in the Greater Natural Buttes field in Uinta Basin, Utah with a cumulative production of 1.8 trillion cubic feet of gas. Most of this production comes from several tight gas formations (matrix permeability of less than 0.01 md). The importance of hydraulic fractures and their interaction with natural fractures in shale gas reservoirs characterized by nano-Darcy permeabilities is well known. This methodology provides a means of mapping a complex (non-planar) network of hydraulically-activated/induced fractures. The initial conductivity distribution in the fractures and the relative permeability of the matrix along with the stress tensor and mechanical properties of the matrix and the fractures control the geometry of the hydraulic fracture system and the ultimate well performance. Prediction of complex hydraulic fracture morphology and injected water balance are important in the development of tight gas and shale gas resources. Multiphase flow simulations with complex fracture networks will help delineate complex effects such as water blocks, "permeability jail" phenomena, etc.
Oil Recovery Enhancement for Thamama B Lower in an Onshore Abu Dhabi Field. Using Conceptual Models to Understand Reservoir Behaviour
Authors: Carvalho Álvaro , Dias Ana , Ribeiro Maria Teresa 
Published: December 2011

Abstract
The Thamama B reservoirs in Abu Dhabi onshore fields represent over 50% of the total reserves of the country. Therefore, the optimization of production and the maximization of recovery are of paramount importance. While reserves are distributed uniformly in the reservoir, the permeability distribution is heterogeneous, with top layers being more permeable (100 mD to 1D than lower ones (1 to 10 mD). This has a strong impact on water flooding performance and requires a thorough understanding of the reservoir fluid flow physics and behaviour, focusing on the detailed analysis of the water hold-up and slumping mechanisms, including the origin and shape of the existing water cones in the lower zones and the bypassed oil zones.
Study results showed that the management of Thamama B reservoirs needs to be achieved through the combination of high quality field surveillance programmes, associated with detailed reservoir studies developed specifically for the modelling of the water advance in the reservoir.
A mechanistic model of a Thamama B reservoir in an Abu Dhabi onshore field was created to determine which parameters, and respective uncertainty ranges, have the greatest impact on fluid dynamics. These were identified to be: rock wettability, (and the associated capillary pressure and relative permeability curves), and the presence of high permeability and dense intervals within the reservoir, both in the upper and lower zones. Once the parameters are identified, it is then vital to reduce the associated uncertainty, by fine tuning the models and undertaking representative forecasts.
The hereby proposed way forward concentrates on monitoring the reservoir performance and build refined reservoir models that can be easily used to understand the reservoir mechanisms and to characterize and accurately predict the water movement in the Thamama B reservoirs, in order to be able to establish the most adequate field development methodologies leading to the optimization of production and to the maximization of ultimate recovery.
Steamdrive Direct Contact Steam Generation for SAGD
Authors: Betzer-Zilevitch Maoz "Moose" 
Published: December 2011

Abstract
In recent years there has been a shift in the Steam Assisted Gravity Drainage (SAGD) steam generation technologies from the traditional Once Through Steam Generator (OTSG) and lime based water softening towards the use of an evaporator and industrial High Pressure (HP) steam boilers. As a result, the available steam temperature and pressure exceeds the steam temperature that is required for injection into the underground formation. This excess steam enthalpy is the driver behind the steam generation method to be proposed.
The method described is a revolutionary process for generating additional steam from highly contaminated oily water with an option for zero liquid waste discharge. The industrial boiler superheated steam is used as the driving force for generating additional steam in a direct contact heat transfer with the contaminated water. Fine Tailings from tailing ponds can be also used. The presented technology generates a "tailor made" pressure and temperature steam, as required for injection into the underground oil bearing formation. This newly developed technology allows generation of additional lower temperature steam from waste water in a high efficiency energy process. The simulation results show that an additional 8% – 24% steam (on a mass basis) can be generated from highly contaminated oily water. The amount of additional steam generated increases with the temperature of the driving steam, and with the reduction of the pressure of the formation. For low pressure shallow formations, additional steam can be produced in comparison to deep, high pressure formations. Another option is to recycle a portion of the produced steam through a heater and use it as the driving steam, and by that minimizing the need for external steam as a heat energy source. A portion of the oil component in the water feed will be converted into hydrocarbon gas that is expected to show similar behavior to a solvent. Additional solvents can be added and injected with the steam to improve the oil recovery. The presented technology has a high thermal efficiency capable of consuming contaminated hot produced water, without the need to reduce their heat to allow effective water treatment. The technology "fits" in the gap between the HP superheated steam and the injection steam while allowing the producers to maximize the advantages and benefits from the use of evaporators and steam boilers for SAGD oil production and can convert the existence of oil contaminate within the feed water into an advantage by replacing the solvent. This steam generation direct contact facility can be located in close proximity to the SAGD pads to use the hot produced water and inject the produced steam into the injection wells.
Effect of Polymer Injection on the Mobility Ratio and Oil Recovery
Authors: Morelato Assunção Pablo , Rodrigues Lorennzo Marrochi , Romero Oldrich Joel 
Published: December 2011

Abstract
The fluids injection in oil reservoirs has the function to supplement the natural energy and in some cases is used to interact with the rock/oil system of reservoir, creating favorable conditions for oil recovery, for example lower interfacial tension, oil swelling, oil viscosity reduction and wettability modification. Polymer injection in heavy oil reservoirs is the subject of extensive studies since its implementation does not depend of major technological devices, requiring only mixing and filtration equipments in addition to those already used for common water injection. Moreover, polymers are not toxic and corrosive and can generate mobility ratios favorable in both borders of the injection seat. The adoption of this solution reduces the water/oil ratio of production, thus reducing the operational costs and consequently creating higher economic return. This work aims to evaluate the potential of polymer injection in heavy oil reservoirs. Therefore, using the reservoir simulation CMG's IMEX, it was analyzed in heavy oil reservoirs the influence of the polymer injection on the mobility ratio, advanced water front during the breakthrough, the oil recovery factor and BSW. Tests with two models of reservoir were performed: homogeneous reservoir and heterogeneous stratified reservoir. Water injection was proposed as a comparison to the polymer injection method.
Advancements in Understanding and Enhancing Biogenic Methane Production from Coals
Authors: Budwill Karen , Koziel Susan , Vidmar John 
Published: December 2011

Abstract
It is estimated that only 5% of Alberta’s CBM reserves are recoverable (Rieb, 2006). A variety of techniques such as horizontal drilling and new fracturing methods have allowed greater recoveries of the methane gas. Alberta Innovates – Technology Futures (formerly the Alberta Research Council) is developing a biotechnology that stimulates and enhances biogenic methane production coal seams. Biogenic methane production is believed to have occurred in the geological past, and is believed to be still occurring in deep, subsurface coal seams albeit at extremely slow rates. It is postulated that the native microorganisms are nutrient limited and, based on laboratory evidence, by adding an organic, nitrogen-rich nutrient, the methane production rate can be increased up to 30-fold over non-amended cutlures. The microbial diversity of Alberta coal seams has begun to be mapped out using state-of-the-art genomic sequencing techniques. It appears the geophysical environment has a strong influence on the types of microbes present as the microbial populations from deeper, more saline Mannville coals are significantly different than the microbes detected in Horseshoe Canyon coals. The microbial population changes upon addition of a nutrient, with shifts occurring in the types of fermenting organisms and methanogenic species. Low molecular weight monocarboxylic acids were observed to be produced and then consumed over the incubation period. These methanogenic precursor substrates accumulated in cultures with only nutrient and no coal. Much lower methane production occurred in these cultures suggesting an unbalanced nutritional state, whereas those cultures with un-limiting carbon from coal and nitrogen source from the nutrient generated large amounts of methane. The effects of surface area, bioavailability of coal moieties and coal porosity and permeability on biogenic methane production are under investigation. Results will aid in the design and deployment of an effective enhanced biogenic methane coal bed field trial.
Investigation of Liquid Loading in Tight Gas Horizontal Wells with a Transient Multiphase Flow Simulator
Authors: Jackson Donald F.B. , Virués Claudio J.J. , Sask David 
Published: December 2011

Abstract
Liquid loading occurs when gas production declines to a rate that is insufficient to lift the associated liquids to surface. At lower rates, gas production becomes intermittent and eventually stops entirely. However, liquid holdup in the horizontal section may impair production before loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow from the horizontal wellbore to the tubing and to an earlier onset of liquid loading in the tubing.
This paper presents liquid holdup data from a single onshore horizontal tight gas well, obtained through video-logging. A transient multiphase flow model is then used to match the observed conditions.
The results from the transient multiphase flow model were found to be consistent with the measured data acquired from the video-logging. Sensitivity analyses were performed with normalized trajectories representing toe-up, toe-down, undulating, and complex drilling profiles. Sensitivities to variations in the liquid-gas ratio and the distribution of the reservoir inflow were also investigated. The results of the transient multiphase flow modelling support the conclusion that complex trajectories are more prone to production losses caused by liquid holdup.
The implications of this conclusion for trajectory optimization and tubing landing depth selection are explored. Modelling liquid holdup can lead to improvements in planning new drilling projects, mitigating the impact of liquid loading on long-term performance.
Study and Application of Heat Self-Generating CO2 Flooding for EHOR
Authors: Zhou Yongbing , Qin Guowei , Fu Shuang , Wang Maosheng , Wang Lei , Zheng Xianbao , Xiao Hongwei , Bai Yanming , Liu Mingjun 
Published: December 2011

Abstract
Heat self-generating CO2 flooding is a new technique combining of steam flooding, gas flooding and so on. Its main mechanism is the application of steam heating self-generating gas agent solution to generate a large volume of gases (including CO2, NH3, etc) in the formation. While some of these gases acting with the crude oil to reduce the oil viscosity, some form miscible flooding to reduce oil/water interfacial tension, so as to achieve the purpose of enhancing heavy oil recovery. An optimized selection of the heat self-generating gas agents was performed. By comparison the difference before and after the reaction of the solution, the increase of alkaline is occurred after the reaction, which is helpful to reduce oil viscosity and lower interfacial tension. Studies indicate that heat-generating CO2 flooding technique can get a maximum viscosity reduction rate of 75.3%, oil/water interfacial tension decreased by 54.18%, and further improve the oil recovery by 4.6% based on the steam flooding, which shows a technical advantage to conventional enhancing oil recovery method. The pilot field shows that the technique can greatly improve the oil production, which will provide a powerful technical supporting for the efficient development of heavy oil.
Effect of Gas Dissolution on Heavy Oil Well Performance: Rheology Considerations
Authors: Dabholkar Dinesh , Mahadevan Jagan 
Published: December 2011

Abstract
Crude oils may exhibit shear rate dependent viscosity under reservoir temperature and pressure conditions due to many factors such as wax content, asphaltenes, solids, and water droplets. In a previous experimental study we investigated the shear rate-shear stress relationship for heavy crude oil using capillary viscometer. The study showed mildly non-Newtonian behavior of heavy oil and the rheological power-law parameters (flow behavior index and flow consistency) depend on the extent of gas dissolution and at higher gas dissolution the fluid flow behavior index approaches unity. Impact of non-Newtonian flow behavior on oil inflow performance can be significant.
In this study, a two dimensional unsteady state model is developed to represent the multiphase flow behavior of heavy oil, accounting for the non-Newtonian behavior and the model is solved using a fully implicit finite difference scheme. In essence, the approach is that of a traditional black oil type of reservoir modeling, but with the viscosity of the heavy oil represented by a power law model. Power law parameters for saturated oil at high temperature and different pressures, obtained from experiments in a companion study are used in modeling the rheology of heavy oil. Modified Darcy’s law is used to model non-Newtonian flow of heavy oil through porous media. Results of the numerical solution are validated with analytical solution of single phase non-Newtonian flow through porous media available in the literature.
Non-Newtonian behavior under reservoir conditions can increase the pressure drawdown required for production by several times and hence affect the production. The well inflow performance calculated using the simulator shows that, as the exponent of the power law model decreases, the production flow rate decreases. Thus, in comparison to a Newtonian behavior, a power law behavior results in a poorer inflow performance. The results presented here may be used to explain higher recoveries in heavy oils which display non-Newtonian behavior. Additionally, strategies for production optimization could be achieved by controlling the fluid rheology and hence the power law parameters by maintaining solution gas in the oil phase.