Measurement and prediction of the rate of deposition of flocculated asphaltene particles from oil

Asphaltene deposition is one of the unresolved problems in oil industries. Little information is available on the critical question of “how fast” the flocculated asphaltene particles deposit across the production wells from the flowing oil. In this study, the mechanisms of deposition of flocculated asphaltene particles from oil have been studied experimentally and theoretically under forced convective conditions using an accurate thermal approach. The effects of oil velocity, flocculated asphaltene concentration and temperature on the rate of asphaltene deposition are investigated. It is observed that during the first few weeks the deposition mechanism is dominant and the erosion of the deposit is almost negligible. The rate of asphaltene deposition increases with increasing flocculated asphaltene concentration and temperature while it decreases with increasing oil velocity. After clarification of the effects of operating parameters on the deposition process, the results of the experiments are used to develop a mechanistic model for the prediction of the rate of asphaltene deposit formation under forced convective conditions. The predictions of the suggested model for the deposition rate of asphaltene are compared with measured data. Quantitative and qualitative agreement between measured and predicted asphaltene deposition rates is good.     

Prediction for wax deposition in oil pipelines validated by field pigging

The deposition of wax in oil pipelines presents a costly production and transportation problem. The deposited wax is removed periodically by pigging operation in field. In this study, in order to understand this problem and address it, a series of wax deposition experiments involved the sloughing effect was performed in the laboratory flow loop, and a model was established to predict the wax deposition distribution along the pipeline. These results were used to implement a pigging program. In addition, a practical experimental method by testing the viscosity of deposit-in-oil slurry ahead of the pig was specially designed to measure the volume of deposit during pigging in actual field. The model predictions agreed with the field measured results excellently with a relative error being −10.9%. Of more importance, some pigging issues are discussed in combination with the data from the laboratory simulations and field pigging operation.     

A time-convolution approach for modeling heat exchange between a wellbore and surrounding formation

In oil, gas, and geothermal energy production, as well as geological CO₂ storage, the target formation is typically deeper than 1000 meters. As a result, associated wellbores have a large heat exchange area with the surrounding formation. Large gradients and temporal variations in temperature induced by the injection and production of fluids require accurate and efficient ways to calculate the heat exchange between fluids in the wellbore and the formation. One way to calculate this heat exchange is to fully discretize and numerically model the formation that surrounds the wellbore. However, because only the energy equation needs to be solved (i.e., there is no fluid exchange between the cased wellbore and the formation), this approach is computationally inefficient. In this work, we propose a time-convolution method, where only the wellbore is fully discretized, and heat exchange between fluids in the wellbore and the formation is calculated using semi-analytical solutions of radial conductive heat flow. The time-dependent temperature evolution in the wellbore is calculated numerically using a wellbore simulator for non-isothermal, multiphase fluid mixtures. At each time step, radial heat transfer with the formation is calculated by superposition of analytical solutions of heat flow that are dependent on the temperature differences between subsequent time steps. This coupling scheme is implemented in the TOUGH2 suite of reservoir simulators. To verify the proposed semi-analytical method and demonstrate its applicability, we present examples and compare them to full numerical solutions.     

A novel technique for screening of asphaltene deposition by the pattern recognition method

Asphaltene precipitation is one of the most common problems in both oil recovery and refinery processes. In oil recovery, formation of asphaltene aggregation followed by deposition causes blocking in the reservoir. This makes the remedial process costly and sometimes uneconomical. Unfortunately, there is no predictive model for asphaltene problem treatment. The problem is very difficult mainly because of the fuzzy nature of asphaltene and the large number of parameters affecting precipitation. In this study, a novel and intelligent method is presented to screen asphaltene stability in oil by using a pattern recognition tool, an intelligent system that utilizes SARA analysis, to determine how severe a problem is.     

Production testing in miravalles geothermal field, Costa Rica

Wellbore deposition of calcium carbonate has occurred in the first wells drilled in the Miravalles geothermal field, Costa Rica. Well PGM-1 was flowtested for periods of 1, 5 and 6 months in 1980, 1981 and 1982, respectively. The well is 1300 m deep and produces from a liquid-dominated reservoir at about 240°C. The flowtests illustrate the time behavior of wells suffering from wellbore deposition. At early time the decrease in output flow rate and wellhead pressure is slow but at late time it becomes rapid; the curves are concave down. The ratio (flow rate/wellhead pressure) remains nearly constant with time for wells suffering calcium carbonate wellbore deposition, at least in the Miravalles geothermal field.     

Experimental and theoretical study of asphaltene deposition and permeability impairment in low-permeability carbonate cores

Asphaltene deposition is one of the problems that oil industries face during oil production, processing, transport, and refining. Deposition of asphaltene flocculation on reservoir rock can plug pore spaces and cause permeability impairment. Carbonate rock, which has low permeability, tend to adsorb asphaltene causing more loss of permeability. In this study, three miscible CO₂ injection core tests were conducted at reservoir conditions and the effects of asphaltene content on the amount of formation damage in carbonate cores with low permeability were investigated. High asphaltene content oil has been used in the experiments. Results show that permeability reduction was more than porosity losses. An empirical model for permeability impairment was derived based on experimental data by considering the activation of the two mechanisms simultaneously. The results may be useful for understanding permeability impairment mechanisms during gas injection in low-permeability carbonate cores.     

冷介质通过井筒注入某地质结构的流动与传热预测软件研发

通过井筒向某地质结构内注入冷介质时,由于地温与冷介质之间存在温差,冷介质将通过井筒结构与土壤进行热量交换,最终导致冷介质冷量损失进而温度升高而达不到所需温度要求。因此,在施工前,需要对井筒进行冷量损失和沿井筒的温度分布的预测,为保冷结构设计以及井筒结构材料选型提供数据支持。由于注入冷介质的过程中,热量交换过程是一个非稳态传热过程,通常只能采用数值模拟来进行预测。为了简化数值模拟复杂的计算过程,采用准稳态的传热方法来构建单相冷介质通过井筒注入时的流动换热的物理数学模型,并开发了一个数值仿真软件。将仿真结果同商业软件FLUENT模拟结果进行了比较,表明温度分布和冷量损失基本一致,由此验证了所提模型的正确性和可靠性,为非工程热物理专业的工程技术人员提供能够预测低温工质在井筒流动与换热过程的仿真软件。     

气动力解堵技术在低渗透油田的应用

油田开发过程中,为保证油井正常生产,洗井和作业是常见的维护措施,在此过程中,不可避免的有部分入井液渗入近井地带,造成污染,导致油井产量下降,油田通常采取酸化措施来恢复油井产能。但当油井近井污染程度严重时,常规的酸化措施不能有效解除污染。为此,近几年发展了解堵能力和作用效果更为明显的气动力深穿透油层复合解堵技术。从理论和现场两方面论述了气动力解堵技术在低产、低渗透油田的应用。技术主要作用机理包括:机械作用、振动脉冲作用、放热作用和化学作用;现场共试验15口井,累计增油1161t。通过地面微地震监测表明,气动力解堵技术可以在油井近井地带产生多条径向裂缝;固井质量检测表明,该技术对固井质量有一定影响,但固井质量仍合格;井下油管有灼痕现象,但油管的力学性能及化学成分未发生变化,仍符合油管标准。     

Coupled reservoir-wellbore simulation of geothermal reservoir behavior

The reservoir simulator TOUGH and the wellbore simulator WFSA have been coupled to model flow of geothermal brine in the reservoir as well as in the wellbore. An outline of the structure of the two computer codes is given, together with the relevant equations. A new module, COUPLE, has been written to serve as an interface between TOUGH and WFSA. Two sample problems are given to illustrate the use of the coupled codes. One of these problems compares the results of the new simulation method to those obtained by using the deliverability option in TOUGH. The coupled computing procedure is shown to simulate more accurately the behavior of a geothermal reservoir under exploitation.     

The numerical simulation and wellbore modelling of steam injection and stored heat recovery from light oil reservoir

ABSTRACT

Steam injection and thermal recovery of oil from the reservoir are increasing day by day. However, the recovery of the heat remained stored in the steam-flooded oil reservoir is nor in practice neither researched previously. A novel concept of steam injection and energy recovery from a light oil reservoir is presented in this paper. Reservoir numerical model of an actual oil field was generated and simulated with steam injection. Different parameters of thermal properties of geologic formations were discussed and adopted as per actual geology of the study area for more realistic simulation of heat storage, dissipation, and losses. After the optimum oil recovery, water was circulated through the same injection well into the reservoir to extract the energy in the form of heat, stored during the steam injection phase. The effects of different completion schemes of injection well were also simulated, discussed and pointed out for optimum oil recovery. Oil recovery factor is the most important parameter from both research and field development point of views. The comparative analysis was also carried out with the oil production without steam injection and found that steam flooding increased oil recovery factor up to more than 15% by decreasing the production time period up to 40% as compared to without steam injection oil production. The transmission of heat through conduction and convection mechanisms in the porous media, and through advective, dispersive and diffusive processes in the fluid was modeled. To fully investigate the feasibility of the concept presented in this paper, the production wellbore modeling was also carried out and temperature profile of recovered heat energy at the wellhead was obtained by acknowledging the thermal losses and found to be very useful for any direct and indirect utilization of heat throughout the energy recovery period of the reservoir.     

Advanced mathematical model for reservoir heat efficiency with liquid in steam-injection wellbore

The accurate determination of reservoir heat efficiency of steam injection in heavy oil reservoirs is very important for heating radius calculation and production dynamic prediction. In conventional calculation methods of reservoir heat efficiency, the steam-injection wellbore is assumed as taking steam over the entire height. In fact, a liquid level in steam-injection wellbore is a very significant observation with respect to the steam override. Aiming at the actual situation that the steam-injection wellbore always has a liquid level, combined with the formation temperature distribution, the new mathematical model for reservoir heat efficiency with the consideration of liquid in steam-injection wellbore was established based on the Van Lookeren steam override theory and the energy conservation principle. The established mathematical model was used to calculate and analyze the reservoir heat efficiency of steam injection in heavy oil reservoirs. The results show that because the new mathematical model considers the liquid in the steam-injection wellbore, the predicted results are more reasonable, thus verifying the correctness of the new model. According to the influential factors analysis based on the new model, it is observed that although increasing the steam quality can effectively increase the steam-taking degree of the steam-injection wellbore, it has limited impact on reservoir heat efficiency. Moreover, the larger the steam-injection rate, the higher the steam-taking degree and reservoir heat efficiency. The reservoir heat efficiency decreases with the pay-zone thickness when the steam-injection wellbore has liquid.     

Simulation of Steam Injection Process for Horizontal Well with Heavy Oil Recovery

Horizontal well technology is widely used in the production of heavy oil. Steady-state model is used as main research method and assume constant wet steam parameters in wellbore, ignoring the impact of heat and mass transfers of steam from wellbore to the reservoir. Numerical calculation is used to analyze steam-water-oil three-phase on flow and heat transfer rule in reservoir and wellbore in startup phase. The influence rule on diffusion process of vapor and water hindered by oil stockpile in wellbore was analyzed, as well as vapor and water parameters change rule along the well. Result indicated that wet steam moving forward was hindered by oil stockpile in wellbore, which lead reservoir suction steam to be not uniform; dryness and temperature of steam gradually reduce, resulting in high temperature at the heel and low temperature at the toe of reservoir; reservoir suction steam effect was improved and reservoir heated range was expanded gradually with the increasing of steam injection volume and dryness; variation of reservoir porosity and permeability have a similar effect on reservoir suction steam, comparing with steam injection volume and dryness. When porosity and permeability were enlarged, reservoir suction steam effect and reservoir heated range would become better.     

新疆油田常规钻机钻浅层稠油水平井钻井完井技术

新疆油田拥有丰富的浅层稠油资源，采用常规直井钻机钻浅层稠油水平井开发因地面距离目的层垂直井段短，使得钻井完井工艺面临一些特定的技术难题。结合新疆油田九8区应用常规钻机及常规水平井工具、仪器，钻成国内垂深最浅（垂深仅146．3m）的HW9802超浅层稠油水平井，从井身结构设计、井眼剖面优选、浅层高造斜率的实现方法、实钻井眼轨迹控制、大尺寸套管柱的安全下人等方面进行介绍。该井完钻井深421．8m，完钻垂深144．09m，井斜91．2°，闭合方位222．17°，水平位移329．42m，成为当时国内应用常规直井钻机所钻垂深最浅的水平井。     

应用"接近零流量法"挖潜杏西油田高水淹井层潜力研究

杏西油田已注水开发22年,随着开发时间的延长,虽然在注水井上采取细分、调剖、周期注水,在采油井上采取堵水等措施稳油控水,但仍有部分井油层水淹程度高、地层能量高,成为高含水井,失去开采价值而关井。但从剩余油分布机理和其他油田开发实践表明,这些井仍有一定的产油潜力。结合现场实践,从井筒内再次成藏角度提出了“接近零流量法”挖潜高水淹井层内剩余油,其主要目的是对特高含水、已经或将要废弃的井层采取间歇生产或尽可能降低产液量方法继续动用。现场实践表明,这种方法可以有效挖潜强水淹井层内的剩余油,是对水驱油田后期开发和挖潜方式的丰富与完善,值得推广应用。     

调驱措施效果预测方法的研究及应用

通过系统地分析区块、单井组调驱后的效果资料,归纳出影响调驱效果的主要因素,结合概率论建立经验统计的效果预测方法．分别预测区块及单井调驱所达到的增油量、降水量、增加的可采储量等指标,从而为调驱措施的有效实施提供可靠的依据。通过在濮城油田东区沙二上1油藏上4口井与濮城浦田西区沙二上2＋3油藏濮4南区的应用．证实该方法应用简便,预测精度高,具有一定的实用性。     

A novel analytical transient heat-conduction time function for heat transfer in steam injection wells considering the wellbore heat capacity

Steam injection technique is one of the most important methods for enhancing the heavy oil production. Evaluating the reliability of steam injection projects requires the investigation of the heat transfer in the wellbore and the surrounding formation. In this study, a new formation heat-transfer model taking into account the wellbore heat capacity was developed and a novel analytical transient heat-conduction time function was presented. Comparison of the formerly used transient heat-conduction time functions with the novel analytical transient heat-conduction time function was made. The result indicated that the wellbore heat capacity has a significant influence on the transient heat-conduction time function, especially for cases of short time injection. To investigate the effect of wellbore heat capacity on the heat transfer in steam injection wells, a comprehensive wellbore/formation model incorporating the novel analytical transient heat-conduction time function was also established. Based on this model, the wellbore/formation interface temperature and the wellbore heat losses were computed by using various transient heat-conduction time functions. The comparisons showed that the formerly used transient heat-conduction time functions would lead to inadequate estimation of the wellbore/formation interface temperature and the wellbore heat losses. High accuracy and excellent applicability of the wellbore/formation model were demonstrated when performances of the proposed model were compared with the measured field data from the steam injection well.     

Modeling of bubble-layer thickness for formulation of one-dimensional interfacial area transport equation in subcooled boiling two-phase flow

In relation to the formulation of one-dimensional interfacial area transport equation in a subcooled boiling flow, the bubble-layer thickness model was introduced to avoid many covariances in cross-sectional averaged interfacial area transport equation in the subcooled boiling flow. The one-dimensional interfacial area transport equation in the subcooled boiling flow was formulated by partitioning a flow region into two regions; boiling two-phase (bubble layer) region and liquid single-phase region. The bubble-layer thickness model assuming the square void peak in the bubble-layer region was developed to predict the bubble-layer thickness of the subcooled boiling flow. The obtained model was evaluated by void fraction profile measured in an internally heated annulus. It was shown that the bubble-layer thickness model could be applied to predict the bubble-layer thickness as well as the void fraction profile. In addition, the constitutive equation for the distribution parameter of the boiling flow in the internally heated annulus, which was used for formulating the bubble-layer thickness model, was developed based on the measured data. The model developed in this study will eventually be used for the development of reliable constitutive relations, which reflect the true transfer mechanisms in subcooled boiling flows.     

注水井转抽技术研究及其应用

低渗透油田采用水驱方法效果较差,最终采收率只有20%。为此,开展了注水井转抽现场试验研究。根据室内实验和水驱油渗流机理,阐述了油田注水井微观出油机理和宏观出油机理,应用理论计算分析和数值方法,定量分析认为,影响注水井转抽效果的主要因素有启动压力、毛管力、到断层的距离、孤立砂体有效厚度等。通过室内核磁共振实验和孔隙结构分析,阐明了换向驱油（注水井转抽）可以提高采收率,在此基础上,从总结矿场试验资料入手,通过地质基础和开发特征研究,提出了适合注水井转抽的地质条件：转抽的注水井要取得较好效果,则注水井到断层的距离应大于50m,或该井钻遇孤立的中高渗透砂体且有效厚度应大于3m。     

A comprehensive simulator for assessing the reliability of a photovoltaic panel peak power tracking system

When designing a maximum power point tracking (MPPT) algorithm, it is often difficult to correctly predict, before field testing, the behavior of this MPPT under varying solar irradiation on photovoltaic (PV) panels. A solution to this problem is to design a maximum power point trackers simulator of a PV system used to test MPPT algorithms. This simulator must have the same role as the MPPT card of the PV panel and thus will fully emulate the response of a real MPPT card of the PV panel. Therefore, it is a good substitute to help to test the peak power trackers of the PV system in the laboratory. This paper describes a simple peak power trackers simulator of the PV system which has a short response time thus, can be used to test MPPT algorithms under very rapid variation condition. The obtained results and the theoretical operation confirm the reliability and the superior performance of the proposed model.