bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Study of the Effects of Lean Zones on SAGD Performance in Periodically Heterogeneous Media
Authors: Xu Jinze , Chen Zhangxin , Cao Jili , Li Ran 
Published: June 2014

Abstract
Highly permeable lean zones that halt the growth of steam chambers through lateral spreading significantly affect the performance of steam-assisted gravity drainage (SAGD). Nexen's Long Lake and Suncor's Firebag SAGD projects reported existence of intersecting lean zones that behave as thief zones, causing the operating pressure to be lower than the desirable value to reduce heat loss in the lean zones. Given a high steam-oil ratio, long and continuous lean zones located vertically above or near a wellbore pose a challenge. Log analyses and core experiments reveal that the distribution of lean zones is close to being periodic in the upper and middle parts of the McMurray Formation in Athabasca. A simulation model with periodic lean zones is established to analyze the effects of these lean zones on SAGD performance.
We investigate the effects of vertical distribution, horizontal spacing and sizes, and spatial relationship with SAGD horizontal wells. We classify the locations of lean zones as above an injector (AI), between an injector and a producer (BIP), and below a producer (BP). For each location, we assign different spacing for neighboring lean zones of different sizes. A lean zone must reach a critical size before this area can act as a thief zone, which is most significant in AI and BIP situations. In general, BP cases are hardly influenced by lean zones. We further control the vertical distribution of these zones using a triangular periodic function that depends on layer depth and connate water saturation. Changing the period of the dominant function yields different kinds of lean zone distribution patterns; we run simulations for each pattern. Results show that lean zones with small periods have significant effects on SAGD performance. We vary the injection pressure to obtain the highest net present value (NPV) based on the fact that more steam is released through the lean zones at a higher pressure.
Phase Behaviour Modeling of Complex Hydrocarbon Systems Applicable to Solvent Assisted Recovery Processes
Authors: Bayestehparvin Bita , Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal 
Published: June 2014

Abstract
Declining production from conventional resources in recent years has fueled increasing global interest in alternative resources, such as heavy oil and bitumen. The design and development of heavy oil and bitumen recovery processes, e.g. solvent-enhanced steam-assisted gravity drainage (ES-SAGD) and hybrid solvent, requires accurate predictions of phase equilibria and the mutual solubility of different solvents in bitumen. Despite the importance of accurate phase behaviour predictions, there is a lack of fundamental and mechanistic knowledge relevant to bitumen/solvent equilibrium properties.
This study provides a better understanding of the phase behaviour of bitumen/solvent systems. A phase behaviour model based on the Peng-Robinson equation of state was developed and validated with existing literature data. Then, available mixing rules for computing the co-volumes of polar and non-polar mixtures were incorporated into the developed model. In order to model the phase behaviour of bitumen/solvent mixtures, bitumen was first characterized to estimate its critical properties based on the boiling point distribution data. The boiling point distribution was modeled and extended using probability distribution functions. The phase behaviour of solvents (e.g. methane, ethane, and carbon dioxide) and Cold Lake bitumen systems were modeled using the developed model and the volume translation technique was applied to improve the saturated liquid densities.
The results show that the van der Waals mixing rule with two regression parameters successfully improves the accuracy of the solubility predictions to less than 4%. Incorporating the temperature dependency of the binary interaction coefficient makes the predictions even more accurate. A correlation incorporating the impact of temperature and component molecular weight on the calculation of saturated liquid densities was proposed for the translated volume values with a 0.6% deviation in density predictions.
The stepwise characterization scheme was developed in this study successfully define bitumen pseudo-components with least needed experimental data. The results also show the van der Waals mixing rule with two binary interaction coefficients predicts solvent solubility superior comparing to previous attempts.
Waterflooding Experiments with X-ray CT Imaging
Authors: London Mike , Cameron Shauna , Donald James , Wassmuth Fred 
Published: June 2014

Abstract
Three experiments have been performed, injecting brine and polymer into a sand pack saturated with heavy oil. Each experiment was imaged with time lapse X-ray CT. The first two experiments, conducted in a medical scanner with a resolution of 350 μm, suggested important features below the scale of spatial resolution. The last experiment, performed in a synchrotron beamline with a resolution of 4.3 μm, provided a view of oil/water interactions on the scale of individual pores.
Conventional theory holds that waterflooding is unstable with respect to the development of fingers, which push the oil ahead of them. "Sweep efficiency" can be improved by increasing the water viscosity with polymer, which reduces the mobility ratio and stabilizes the front. Waterflooding has been applied successfully to heavy oil, but the detailed mechanisms of recovery are not well understood. Breakthrough of water occurs quickly at the producer; most oil production occurs at high water cuts over a long period of time.
The most striking feature of the medical scans was the absence of distinct fingers of high water saturation. The only identifiable, compact "front" consisted of saturation changes of 20% or less. Moreover, breakthrough occurred long before the front reached the production end of the pack. More surprisingly, water saturation was observed to increase everywhere throughout each experiment. The inference was that fingering, if present, was occurring at a scale below that of the resolution. The synchrotron scans did not reveal the expected pore scale fingering, but instead showed evidence of water transport entirely in wetting films. Residual blobs of connate water were observed to grow throughout, but never linked up to form fully water-saturated paths.
The mechanism of oil mobilization was also quite different from the traditional picture. There was no scale at which oil was pushed ahead of a water front. Instead, isolated droplets of immobile water swelled, fed by films of water on the grain surfaces. These results do not rule out an eventual transition to a more conventional picture; only a few pore volumes were injected. But the path to that state may be different from what is usually assumed.
Kinetic Modeling of the In-Situ Combustion Process for Athabasca Oil Sands
Authors: Chen X. , Chen Z. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Harding T. G. 
Published: June 2014

Abstract
In-situ combustion (ISC) is an effective thermal recovery method that provides an important alternative to steam injection, but it has yet to be widely applied due to the complexity of the process. The modeling of ISC requires an understanding of the behavior of different physical phenomena including phase change, heat and mass transfer, and chemical reactions. Properly conducted ramped temperature oxidation (RTO) tests on crude oil provide critical parameters for modeling. In this study, the focus is to model appropriate kinetics and improve reaction models for ISC.
Different chemical reactions occur during ISC in different temperature ranges. For heavy oils and oil sands low temperature oxidation (LTO) dominates below 260°C, yielding partially oxygenated compounds and increasing the viscosity of oil, and as a result, limiting the success of the ISC process. The so-called middle temperature oxidation (MTO) region is a combination of the negative temperature gradient region (NTGR) as well as the onset of thermal decomposition and pyrolysis/cracking of the hydrocarbon phase, some or all of which may have been previously oxidized. Above 350°C, high temperature oxidation (HTO) dominates, representing the more commonly known traditional combustion region. Most of the current reaction kinetics models for ISC only focus on specific conditions such as HTO and are not able to represent the wide range of reactions that occur over a larger temperature range.
The objective of this study was to develop reaction kinetic models that can be used to describe the reactions of hydrocarbon fractions at various temperature conditions during the ISC of Athabasca bitumen. In this work, a set of improved kinetic models including LTO, MTO, and HTO reactions based on Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions in the crude oil are established. These kinetic models are used to reproduce the RTO experimental results through numerical simulation. This research will contribute to the development of more reliable numerical models that can predict ISC performance in different temperature scenarios with greater accuracy and reliability.
Development of a Microfluidic Device for Rapid Assessment of EOR Additives
Authors: Lele P. , Fadaei H. , Guerrero U. , Sinton D. 
Published: June 2014

Abstract
Microfluidics permits small scale economically controllable testing/analysis environments, and has been leveraged in biochemistry and the life sciences to access previously unavailable efficiencies, most notably in DNA sequencing, protein analysis, and soft material (e.g. tissues, emulsions) synthesis. Recently, these techniques have been applied to petroleum science and the results show promise. Methods have been reported in the literature for studying CO2 diffusion, investigating reservoir fluid phase behaviour, and asphaltene content measurement. These methods drastically reduce sample volume (from litres to nanolitres) and measurement time (from several hours or days to 30 minutes or less) requirements, while maintaining or increasing accuracy offered by traditional methods. In the present study, we used microfluidics to simulate the situation where emulsions form in the SAGD process in two situations; pure steam injection and steam + additives injection. Emulsions were generated in pore-scale geometries (~ 100 µm) without and with an alkaline additive. It was found that alkaline solutions produced finer emulsions (by up to nn%). A weak dependence of mean emulsion diameter on additive concentration was also observed. In addition to informing improvements to EOR, the platform may be adapted for use in studying emulsions formed during oil and gas processing as well (e.g. in valves, pumps).
Chemical Reaction Mechanisms That Govern Oxidation Rates During In-Situ Combustion and High-Pressure Air Injection
Authors: Freitag N. P. 
Published: June 2014

Abstract
The lack of an accurate reaction model for petroleum oxidation rates is a serious hindrance to the simulation of oil-recovery processes that involve air injection. However, the chemical literature on hydrocarbon oxidation contains many examples of possible reaction mechanisms that could serve as guides. These mechanisms were screened to identify generally accepted reaction paths that could help reveal how oxidation occurs in petroleum reservoirs.
It was found that there are at least seven groups of fundamental reactions that can seriously affect oxidation rates of crude oils. These seven reactions are as follows: two that lead to hydroperoxide formation; "branching" by hydroperoxides; two reactions governing the negative temperature coefficient region; oxidation inhibition; and at least one rate-controlling reaction at very high temperatures. Each of these groups exerts an influence within a separate, identifiable range of conditions. These reactions, and the conditions under which they become important, are outlined in this paper.
Various oxidation behaviours that have been reported for both light and heavy crude oils were then compared and aligned with the seven identified reactions. The result was a framework for selecting pseudoreactions that can facilitate the prediction of the oxidation kinetics under a wide range of oilfield conditions. Some of these pseudoreactions involve the direct representation of free radicals or other chemical intermediates, which is a departure from conventional practice for in-situ combustion simulation.
The new reaction framework is expected to serve as a reliable guide to the construction of predictive reaction models and, consequently, improved simulation of both in-situ combustion and high-pressure air injection processes.
Feasibility Study of Using Polymer to Improve SAGD Performance in Oil Sands with Top Water
Authors: Zhou Xiang , Zeng Fanhua 
Published: June 2014

Abstract
In western Canada, there are significant amounts of oil sands reserves that have little or no cap rock with a top water zone (Alturiki et al. 2011); because of huge heat loss, conventional SAGD process is uneconomical when it is directly applied in this type of reserves.
In this study, it is proposed that high temperature polymer can be injected into the bottom of the top water zone to establish a stable high viscosity layer in order to prevent steam from leaking to the top water zone. Lab tests were first conducted to screen the polymers. In order to select a proper polymer which was able to have stable viscosity under high temperature, viscosities of different polymers at different temperatures were measured; and concentration of the selected polymer was optimized. Then numerical simulations were performed to evaluate the feasibility of using the selected polymer to improve SAGD performance in oil sands with top water. The numerical simulation model was based on Athabasca oil sands reservoir. In this formation, the top water zone was around 94 meters, while the reservoir thickness was about 30 meters. The vertical permeability was 50 mD and 1,400 mD for the top water zone and the oil zone, respectively. And the porosity was 10% for the top water zone and 30% for the oil zone. The effect of the polymer injection strategy including the polymer injection parameters, such as polymer slug size, injection rate, injection time and well distance on the performance of SAGD process was studied.
The numerical simulation results suggested that, polymer injection was able to block the heat from leaking to the top water zone. With polymer injection, the cSOR can be reduced from 8.5 m3/m3 to 4.8 m3/m3, while for the case without top water, the cSOR was 3.8 m3/m3. This indicates that polymer injection is technically feasible to improve SAGD performance in oil sands with top water.
Effects of Pressure Decline Rate on the Post-CHOPS Cyclic Solvent Injection Process
Authors: Du Zhongwei , Zeng Fanhuz , Chan Christine 
Published: June 2014

Abstract
Cyclic Solvent Injection (CSI) has been proposed as a follow-up process in post-CHOPS reservoirs. The oil recovery factor, which could reach over 50% in lab-scale, is mainly attributed to solution gas drive and foamy oil flow in CSI process. It has been suggested that pressure decline rate has impact on the behavior of solution gas drive and foamy oil flow in cold heavy oil production. However, the role of pressure decline rate in the post-CHOPS CSI process production has not been studied adequately. This work was intended to evaluate the effects of pressure decline rate in CSI process under post-CHOPS reservoirs' conditions.
In this study, different pressure decline rate tests were conducted in a large cylindrical sand-pack model with a length of 30.48 and a diameter of 15.24. Single well was applied and connected with a mimic wormhole. In terms of oil recovery factor, the average recovery factor of each cycle increases with the increasing pressure decline rate. But considering the running time, the tests with smaller pressure decline rates showed better total recoveries compared with the tests with larger pressure decline rates. And the residual oil saturation pictures showed that the oil far away from the wellbore could be more easily recovered when a smaller pressure decline rate is applied. In terms of oil production rate, the CSI process production can be typically divided into two phases. In Phase 1, the production rate increases and reaches to the maximum value. In Phase 2, the production rate significantly declines. It was found that the test with a larger pressure decline rate had the higher production rate in Phase 1, while the test with the smaller pressure decline rate had the longest production time in Phase 1. The production rate hardly has dependence on the pressure decline rate in Phase 2. This indicated that for an optimized CSI process the pressure decline rate should be dynamically adjusted in order to have the best performance. The results also suggested that the minimum production pressure exists, below which no oil or marginal amount of oil was produced.
Are Existing Three Phase Relative Permeability Models Adequate in Modeling Heavy Oil WAG Processes?
Authors: Saliu Olufemi W. , Sohrabi Mehran , Shaverdi Hamidreza 
Published: June 2014

Abstract
Three-phase relative permeability for oil water and gas are very important input to the simulating of three phase flow processes in oil reservoirs. The existing models developed through the observation of recovery mechanisms in conventional oil, use both oil-water and oil-gas two phase relative permeability functions in generating three phase relative permeability functions. But given that the existing three phase relative permeability models were developed for conventional oil which has a different recovery mechanism from heavy oil, could they still be used in simulating three phase flow processes in heavy oil?
This paper attempts to answer this question by examining the recovery mechanism in three phase flow processes in conventional oil vis-a-vis same process in heavy oil through micro-model experiments. A Water Alternate CO2 flood of a heavy oil sample in a core flood experiment was then simulated using the existing three phase relative permeability models.
A comparison of the simulation and the core flood results shows that the existing three phase relative permeability models are inadequate in simulating three phase processes in heavy oil production. An alternative approach using an in-house three phase flow simulator was used in generating a three phase relative permeability curves was used. There is also a proposal of a new three phase relative permeability model for heavy oil. Experimental works have proved that the Water alternate Gas (WAG) flooding process is an effective enhanced oil recovery method for heavy oil production. The residual oil in a core/reservoir after a water flooding can be further reduced through a gas flooding or vice versa. A simulation of this process is very necessary for its optimization. Hence there is a need to have a robust three phase flow simulator for heavy oil.
Stochastic Life Cycle Approach to Assess Wellbore Integrity for CO2 Geological Storage
Authors: Nabih Ahmad , Chalaturnyk Richard 
Published: June 2014

Abstract
Storage sites associated with depleted oil and gas reservoirs may contain many abandoned wellbores in addition to potentially unidentified wellbores. These wellbores have historically variable quality and quantity of cement that will have undergone ranging degrees of degradation. Wellbore performance in a single wellbore is dependent on the wellbore events (i.e. pressure and temperature changes) that occur within the life of the wellbore (Fourmaintraux et al., 2005; Gray et al., 2007).
There is significant uncertainty surrounding the integrity of existing wellbores due to a lack of data. Successful implementation of carbon capture and storage (CCS) will depend on solving the small-scale leakage problem associated with localized flow along wellbores. Our knowledge of oil wellbore performance under different life stages of a well is still weak. Consequently, each wellbore is unique and general conclusions about well integrity are difficult to ascertain from analyzing only a single well. Each wellbore is considered as a risk and robust tools are needed to allow for the assessment of the performance for wellbores and investigate wellbore leakage mechanism.
In this paper, a full lifecycle methodology is proposed to assess wellbore integrity as a measure of the risk of leakage. The methodology identifies the key elements to model the wellbore element and incorporates the use of a statistical approach to better understand the uncertainty in the risk estimation and interaction between various parameters controlling the model.
Could VES be a part of a Hybrid Option to Recover Heavy oil in Complex Heavy oil Reservoirs
Authors: Azad M. S. , Sultan A. S. , Nuaim S. A. , Mahmoud M. A. , Hussein I. A 
Published: June 2014

Abstract
Heavy oil reserves accounts for more than 8 trillion barrels of the total reserve. Thermal methods such as steam flooding (SF) and its variants have been applied extensively to develop the reserves. Complex heavy oil reservoirs possess certain properties that make the steam flooding ineffective. The properties include low thickness, deeper depth and formation nature (naturally fractured carbonates). Heat losses, gravity override and channeling are the common problems associated with it. Polymer flooding (PF) is one of the major non-thermal methods employed to recover heavy oil. Higher Salinity and divalency in carbonate reservoirs restricts polymer flooding applications. Higher oil viscosity also limits its application.
In this work, we investigated the potential of viscoelastic surfactant (VES) in recovering heavy oil in complex reservoirs where steam-flooding and polymer flooding fail. VES exhibits certain unique properties which are ascertained individually. The properties include IFT reduction, viscosity, elasticity, emulsification, salinity resistance, compatibility, and thermal stability. The properties of VES extend its applicability in complex reservoirs and hybrid technique that combined the synergism of VES, P, and hot water has been investigated.
Reservoir simulation studies with 5-spot pattern have been conducted to compare the performance of Steam flood, polymer flood, and hybrid VES flooding in thin heavy oil reservoirs. Results indicated that VES could be an ideal hybrid option along with hot water to recover high viscous heavy oil in thin reservoirs.