风城油田重18井区超稠油油藏注气方式优化选择研究

水平井热采模式一直是改善特、超稠油油藏开发效果的有效手段。在热采中后期,常规同采同注的注气方式存在着蒸汽热利用率低、蒸汽波及范围小和剩余油量大等问题。研究不同注气方式对该类油藏开发效果和经济效益的影响,研究表明,水平井组一注多采和直平井组合吞吐方式均能很大程度提高蒸汽利用率,有效驱替井间的剩余油。     

Formation of coke during thermal hydrocracking of Athabasca bitumen

The formation of two structurally different cokes during thermal hydrocracking of Athabasca bitumen is attributed to differences in coking properties of the asphaltenes and the deasphalted heavy oils. The grain-mosaic coke structure formed from the asphaltenes may be ascribed to the presence of crosslinkage groups derived from the phenolic character of this fraction of the bitumen. Carbonization of the deasphalted heavy oils of the bitumen results in a flow-type coke structure. These two cokes appear to form independently of each other and can therefore be readily identified in samples collected from the reactor.     

A benchmark assessment of residues: comparison of Athabasca bitumen with conventional and heavy crudes

Compared to benchmark crude oils, bitumen does not respond well to conventional upgrading processes. In order to improve our understanding of this problem, we compare the chemical and physical properties of fractions from super critical fluid extraction of bitumen pitch with the corresponding fractions of residua from Venezuelan heavy oil, a Saudi Arabian light crude and a Chinese Daqing conventional crude.Relatively minor differences in chemical structure were observed between the corresponding residua fractions from Athabasca bitumen, Venezuelan heavy oil and Saudi Arabian light crude. Only the Chinese Daqing showed significant variance; this sample is much more aliphatic and has greater geometrical dimensions than the corresponding samples from the other residua.The end-cut from Athabasca bitumen pitch contained ultra-fine solids together with much higher levels of nickel, vanadium and nitrogen than the conventional crude end-cuts. These components are among the most intractable in upgrading and could be responsible for the problems encountered in bitumen upgrading, especially by catalytic processes.     

In situ upgrading of bitumen and heavy oils via nanocatalysis

Thermal in situ bitumen production has introduced a different engineering approach compared to conventional oil exploitation. Steam injection for example, allows the development of a relatively confined liquid and gas chamber surrounding and along the length of the production wells. This heated place can be converted into a reactor for upgrading processes founding expectations of extensive reservoir upgrading of unconventional oils reducing the total energy currently required to both exploit the reservoir and surface upgrade the produced bitumen. These could also selectively transform contaminants into harmless products remaining in the reservoir. This article highlights the nanocatalytic in situ upgrading paths that may result in economical and environmentally efficient oil sands exploitation. © 2012 Canadian Society for Chemical Engineering     

Microwave applications to oil sands and petroleum: A review

This review provides a general overview of microwave applications in oil sands bitumen or shale oil production in petroleum upgrading. The vast oil reserves in the oil sands of Alberta will become a major source of petroleum products in the near future and a number of alternative technologies have been explored for the production and upgrading of oil sands and heavy oil. This study is based primarily on the unique selective heating capacity associated with exposure of materials to microwaves. Of particular interest are applications of microwaves for bitumen extraction, upgrading heavy oils, removing heteroatoms, and the underground heating of oil sands to reduce bitumen viscosity and allow it to be pumped to the surface. The fundamentally different method of transferring energy from the source to the sample is the main advantage of utilizing microwave energy. By directly delivering energy to microwave-absorbing materials, conventional issues such as long heating periods and energy loses can be minimized. Microwave energy was shown to be effective in some applications; however, it is not used commercially at the present time.     

稠油油藏深部微乳酸酸化体系研究

油井生产过程中近井地带渗透率逐渐下降,利用酸蚀作用可提高渗透率。微乳酸体系把常规酸与油、表面活性剂以及助表面活性剂混合形成一种均匀、透明的体系,具有很高的稳定性,油/水界面张力超低,利用微乳酸进行稠油油藏深部酸化,对油井和水井解堵具有广泛的应用前景。     

The effect of bitumen molecular fractions on diffusivity and rheology of bitumen under high-temperature conditions: Molecular dynamics (MD) simulation study

Heavy oil and bitumen play an incredible role in Canada's energy resources. The main processes that have already been applied to produce heavy oil and bitumen are in-situ thermal methods. The primary mechanism of production in these reservoirs is a reduction in heavy oil and bitumen viscosities via heat transfer. Having deep knowledge about the rheological behaviour of heavy oil and bitumen is crucial to designing a more accurate and efficient in-situ thermal recovery method. In this work, molecular dynamics (MD) simulation was used to model the rheological behaviour of bitumen under different temperatures. According to MD outputs, the highest diffusion coefficient between bitumen fractions belongs to saturate fractions. On the other hand, the lowest diffusion coefficient belongs to asphaltene fractions. The size of asphaltene, its polarity, and the polarity of a resin fraction affect the diffusion coefficient of asphaltene in a bitumen sample and its rheological behaviour. The MD simulation aims to provide molecular insights and essential information about the rheological trend of bitumen under different thermodynamic conditions. The results of the current work provide essential information about the effect of bitumen fractions on its rheological behaviour.     

Potential for hydrogen generation from in situ combustion of Athabasca bitumen

The volume of heavy oil and bitumen in Alberta, Canada is estimated to be about 1.7 trillion barrels. The majority of the produced heavy oil and bitumen in Alberta is converted in surface upgraders to synthetic crude oil, a crude oil with API gravity typically between 31 and 33° API, which in turn can be converted to fuel, lubricant, and petrochemical products in standard refineries. To upgrade bitumen requires hydrogen. In current practice, much of this hydrogen is generated from catalytic steam reforming of methane together with the water-gas shift reaction. This means that heavy oil and bitumen upgrading, as is currently done, requires large amounts of natural gas to generate hydrogen. The potential for in situ generation of hydrogen by gasification of bitumen reservoirs offers an attractive alternative which can also have both economic and environmental benefits. For example, hydrogen generated from bitumen gasification can also be used for in situ upgrading as well as feedstock for ammonia and other chemicals. The water-gas shift reaction also generates carbon dioxide which could be potentially sequestered in an in situ gasification process so that emissions to the atmosphere are reduced. This technology provides a potential clean method to produce fuel and feedstock material from bitumen, a relatively “dirty” fuel and feedstock oil, in addition to more energy efficient ways of extracting in situ heavy oils. However, to design in situ bitumen gasification processes requires a reaction model that provides a reasonable representation of the gasification reactions. Here, a new kinetic model is developed to examine the potential for hydrogen generation from Athabasca bitumen. The kinetic model consists of thermal cracking, oxidation/combustion, hydrogen generation and hydrogen consumption reactions. A comparison of the simulation results and experimental data from the published literature reveal that the new model can predict hydrogen generation from gasification of methane, Athabasca bitumen, and coke.     

Thermal destabilisation of bitumen-in-water emulsions - A spinning drop tensiometry study

Nonionic surfactant-stabilised oil-in-water emulsions offer a potentially useful vehicle for transporting heavy crude oils from oilfields to refineries or distribution terminals. Prior to refining, separation of the oil from the emulsion is necessary. Previous studies have suggested that heating the emulsion is sufficient for destabilisation and recovery of the oil. The present work examines this process on a batch laboratory scale and monitors the effect of thermal treatment on the heavy oil/water interfacial tension using spinning drop tensiometry. The present research has confirmed that heating Wolf Lake (Canada) bitumen-in-water emulsions to a temperature close to the cloud point of the surfactant results in efficient bitumen/water resolution, together with separation of a dense surfactant-rich coacervate phase that could recycled in a commercial heavy oil transportation process. The corresponding temperature dependence of the bitumen/water interfacial tension provides further insight into the emulsion resolution process.     

Estimation of thermal maturity status of petroleum asphaltenes and maltenes

Asphaltenes from various bituminous sand, heavy oil and conventional oil reservoirs and maltenes from various conventional oil reservoirs have been pyrolysed at 130 °C (for the asphaltenes), and at 50 °C (for the maltenes) in the presence of hydrated aluminium chloride crystals as catalyst for the decomposition. The rates of production of gases were appreciable and measurable. Asphaltenes from bituminous sands from the same geographical location showed a clear correlation between the rate of gas production and the depth of burial. The trend indicates that the thermal maturity of the oil increases with increase in the depth of burial. For conventional oils, a correlation was also observed between the rate of the gaseous product yields and the geological age. Maltenes from the conventional oils gave similar results: here the trend indicates that the thermal maturity of the oils increases with increase in geological age. From the derived correlation curve, the geological age of unknown crude oil was determined (525 × 10⁶ years: middle Ordovician age).     

稠油油藏蒸汽辅助重力泄油参数优化研究

在SAGD开采过程中,蒸汽腔的形成与发育直接影响着最终开发效果的好坏,在泄油过程中,蒸汽腔的大小、泄油能力不断在改变,蒸汽—油界面不断在移动,为防止蒸汽突破进入生产井或者热油积聚在蒸汽腔底部压迫蒸汽腔,必须对蒸汽腔的扩展状况以及油层温度场、压力场以及含油饱和度场进行动态模拟。本文应用STARTS数值模拟软件,对注采井间进行局部加密,精细模拟井间温度、压力场,对直井—水平井组合的SAGD技术的布井参数、注采参数等进行了优化设计,并对开发效果进行了预测。验证了运用数值模拟方法研究蒸汽辅助重力泄油技术开发效果的可行性和蒸汽辅助重力泄油技术开发超稠油油藏的可行性。     

Stability of the edge of a SAGD steam chamber in a bitumen reservoir

Steam-Assisted Gravity Drainage (SAGD) is a key in-situ recovery process being used today to extract oil from bitumen reservoirs. In SAGD, an oil-depleted chamber of steam grows within the oil sands formation along a pair of horizontal wells and heats bitumen-laden oil sands at its edge. The viscosity of bitumen drops by up to five orders of magnitude when heated to above 200 °C and mobilized bitumen at the chamber edge flows under gravity to a production well located at the base of the chamber. If the steam chamber does not grow uniformly along the wellpair, then bitumen recovery is less than ideal. To raise the thermal efficiency, and consequently the economics, of the process, efficient heat transfer from chamber to the oil sands must occur and the chamber must grow uniformly along the entire length of the wellpair. If steam fingers develop at the edge of the chamber, then the heat transfer area enlarges and raises the thermal efficiency of the process since more heat is directed to the oil sands. In this research, the stability of the interface between the steam chamber and oil sands is examined by using linear stability theory. The results show that the stability is controlled by the difference between the energy content-weighted Darcy–Rayleigh numbers of the steam/water phases (displacing fluid) and the oil phase (displaced fluid). Also, the results show that at typical SAGD steam saturation temperatures, the chamber edge is unstable providing the steam quality at the edge exceeds about 50%.     

Steam flow law in horizontal wells when considering reservoir heterogeneity

Steam injection in horizontal wells for thermal recovery of heavy oil is a complex and changeable process. The prediction of thermal properties of steam along horizontal wells is critical to the uniform production of reservoirs. In this paper, considering the mutual coupling effects of reservoir permeability, confining pressure, and steam phase transition, a comprehensive mathematical model for predicting steam injection flow in horizontal wells was established. Compared with the on-site logging data, the accuracy of the model was verified. The simulation results show that under a single variable condition, the larger the steam injection pressure at the heel, the faster the mass flow and steam dryness decrease. When the steam injection pressure drops from 11 MPa to 8.5 MPa, the steam distribution distance doubles. At the same position, the higher the steam dryness at the heel, the greater the mass flow in the steam injection well, and the faster the steam pressure decrease. Double the steam injection dryness, the pressure drop is almost doubled, but the longer steam injection distance. The larger the steam injection flow at the heel, the faster the steam pressure decreases, and the decrease in the steam dryness in the tube slows down. When the steam injection flow increases by 1.75 times, the pressure drop increases by 5.3 times. The higher the reservoir permeability, the faster the steam dryness decreases. By obtaining the general rules of steam distribution in horizontal wells to provide theoretical support for on-site steam injection, the steam distribution effect can be effectively improved to increase production and reduce consumption.     

Thermo‐physical properties of n‐pentane/bitumen and n‐hexane/bitumen mixture systems

The gravity drainage as a result of viscosity reduction is the main governing mechanism of the solvent‐aided thermal bitumen recovery processes. Therefore, the density and viscosity of the diluted or heated bitumen are essential to predict the oil production rate. In this paper, we report thermo‐physical properties of n‐pentane/bitumen and n‐hexane/bitumen mixtures. The density and viscosity of Athabasca bitumen diluted with n‐pentane and n‐hexane were measured at different temperatures (30 to 190 °C), pressures (2 to 8 MPa), and solvent mass fractions (0.05 to 0.5). Various correlations and mixing rules proposed in the literature were examined to calculate the density and viscosity of the diluted bitumen. This study proposes appropriate mixing rules and generalized parameters for predicting the density and viscosity of solvent‐bitumen systems. Our findings will find applications in the design and simulation of heavy oil and bitumen solvent‐aided thermal recovery processes.     

考虑储层非均质时注汽井内蒸汽流动规律

稠油热采水平井注蒸汽是一个复杂多变的过程,水平井沿程蒸汽热物性的预测对于储层的均匀动用十分关键。考虑储层渗透率、围压和蒸汽相变等条件的相互耦合影响,建立了预测水平井注汽流动的综合数学模型。与现场测井数据进行对比分析,验证了模型的准确度。模拟结果表明,单一变量条件下,水平井跟部注汽压力越大,注汽井内质量流量和蒸汽干度下降越快,当注汽压力由11 MPa降为8.5 MPa时,配汽距离增加1倍;在水平井相同位置处,跟部注汽干度越高,注汽井内质量流量越大,且蒸汽压力下降越快,注汽干度提高1倍时,压降也几乎增加1倍;跟部注汽流量越大,蒸汽压力下降越快,注汽流量提高1.75倍时压降提高了5.3倍,但管内蒸汽干度下降趋缓;储层渗透率越高,注汽井内的蒸汽干度下降越快。该模型可以为现场注汽提供理论支撑,有效提高配汽效果达到增产降耗。     

稠油和沥青VAPEX技术影响因素的研究进展

由于常规稀油石油资源逐渐枯竭,作为非常规石油资源的稠油和沥青的开采日益重要,稠油和沥青的蒸气萃取（VAPEX）技术已经成为一项非常有前途的开采工艺。本文讨论了影响稠油和沥青VAPEX技术的各种因素,包括稠油黏度,溶剂在稠油中的扩散系数,溶剂的分散度,溶剂注入时的温度、压力,溶剂的注入速度,地质因素等。列出了这些因素之间重要的数学关系式以及这些因素与稠油和沥青质产量之间的数学模型,对VAPEX技术发展前景和未来研究方向进行了总体展望：由于模型与实际油藏的差异造成结果偏差因而需修正实验模型;VAPEX和SAGD的混合使用;不同温度、压力下溶剂的扩散系数;混合溶剂的使用。     

昆仑-欢喜岭SBS改性沥青的稳定性研究

昆仑-欢喜岭重交通道路沥青与SBS具有良好的配伍性,采用适当工艺,选择良好配伍的SBS改性剂,添加不同类型的稳定剂,使SBS与稳定剂发生化学反应,降低两种材料的界面能。对比基于现场改性不添加稳定剂的改性沥青,热储存稳定性及高温性能均明显改善,适于基地式生产并较长时间贮存,使用性能优异。     

Solid state 13C nuclear magnetic resonance of heavy oil/bitumen-derived solids

Solid state ¹³C n.m.r. analysis of the insoluble organic matter associated with the clay mineral, silica, and heavy metal minerals of heavy oils/bitumen is reported. The conditions under which these measurements can be made are related to the concentration of organic matter found, the nature and amount of paramagnetic constituents, and contact times. The data are related to changes in hydrophilic/hydrophobic surface properties of the solids. The relationship with bitumen losses in recovery processes is also discussed.     

Laboratory study of solvent enhanced communication in oil sands

Miscible displacement experiments were carried out to evaluate the potential of solvents in enlarging fractures between wells to allow for larger volumes of steam to be injected during in situ recovery operations in the Athabasca oil sands deposit. The solvents tested included carbon disulfide, toluene and a series of refinery streams and diesel oils. Since incomplete miscibility between bitumen and some solvents caused asphaltenes to precipitate, solvents were ranked in terms of bitumen compatibility. Solvents such as diesel DP-40 and diesel DC-40, which are intermediate in terms of solubilizing bitumen, were the most efficient in developing zones of low bitumen saturation around an initial fracture and at the same time not extracting bitumen from other regions of the bed. The effects of flow rate and cell orientation on solvent efficiency and permeability are also described. Solvent losses corresponded to about the residual saturation of oil after waterflooding.     

重18井区八道湾组超稠油油藏水平井开发效果影响因素分析

水平井蒸汽吞吐开采超稠油是一项非常有潜力、有优势的技术,相比直井开发,不仅能大幅度提高开发效果,而且能够进一步提高采收率。研究稠油油藏水平井蒸汽吞吐开发效果,分析地质参数及注汽参数对该类油藏开发效果的影响程度,并进行灰色关联分析。研究表明对周期产油量影响最大的因素是采注比,其次是原油粘度。