Влияние полимеров и сополимеров олефинов на турбулентное течение углеводородных жидкостей

Drag reducing additives (DRA) are widely used to increase the pipeline capacity in oil and refined products transit. Introducing DRA at a rate of 1–5 ppm results in considerable lowering of pumping energy. To predict the capability of concerned polymer as a DRA we tried to give an effectiveness theoretical justification in terms of its chemical composition. It was shown that the most effective oil-soluble polymers relate to higher poly(1-alkenes) of superhigh molecular weight (M > 106). Additionally, the nature of the solvent is of importance. 1-Hexene polymerization in the presence of Zigler–Natta catalysts gives a super high molecular weight polymer which is the most effective drag reducer among the higher poly(1-alkenes). But if environment provide some limitation in poly(1-hexene) solubility, such as temperature lowering, or asphaltene content increasing the (co)polymers of 1-octene and 1-decene become the best. Для интенсификации перекачки нефти и нефтепродуктов по магистральным трубопроводам в настоящее время широко используют противотурбулентные присадки, при введении которых в турбулентный поток в предельно малой концентрации (C = 1–5 г/м3) наблюдается уменьшение энергетических затрат на транспортировку углеводородной жидкости. С целью прогнозирования перспективы промышленного использования присадки той или иной химической природы в настоящей работе представлено теоретическое обоснование и экспериментальное подтверждение эффективности различных полимеров. Установлено, что из всех нефтерастворимых полимеров наилучшими противотурбулентными свойствами обладают высшие поли-α-олефины со сверхвысокой молекулярной массой (Мr > 1·106). Также выявлено влияние компонентного состава и термодинамического качества растворителя на эффективность присадок, причем эти факторы следует рассматривать в совокупности. Например, цепь полимера, обогащенная гексеном, при прочих равных условиях синтеза имеет большую молекулярную массу, и такой полимер в хорошем растворителе снижает сопротивление лучше своих аналогов. Тем не менее, если превалируют факторы, ограничивающие растворимость полигексена (низкая температура, обилие асфальтенов в нефти), предпочтительными оказываются полимеры и сополимеры октена и децена, имеющие более низкую температуру стеклования.

Investigation of Influential parameters on Oil/Water Interfacial Tension during Low-salinity water Injection

Injecting low-salinity water has proved to be an efficient displacement process in oil reservoirs, owing to its ability to modify the properties at the fluid-rock and fluid-fluid interfaces in favor of mobilizing more oil. In this regard, reduction of interfacial tension (IFT) between oil and water is one of the key controlling parameters. It is suspected that the asphaltene constituents of the oil and type of water ions are responsible for such a reduction in IFT. In this study, systematic experimental investigations were carried out to scrutinize the influence of brine salinity, asphaltene concentration and temperature on IFT. Single and multi-component brines, which in particular compose of NaCl, CaCl2, and MgCl2 salts, and two synthetic oils with 1 and 10 wt% asphaltene content were used at temperatures ranging from 25 to 80°C. The results showed that the presence of salt in the solution can alter the distribution of polar components at the oil-brine interface due to the electrostatic effects, which in turn would change IFT of the system. IFT also decreased when temperature increased from 25 to 80°C, however the level of changes was strongly depended on the brine type, salinity level and asphaltene content. The results also demonstrated that the crude oil with the higher asphaltene concentration experiences higher IFT reduction when is contacted with the low-salinity water. The new findings from this study will improve the understanding of the underlying mechanisms for low salinity water flooding in oil reservoirs.

Asphaltene Deposition during CO2 Flooding in Ultralow Permeability Reservoirs: A Case Study from Changqing Oil Field

Asphaltene deposition is a common phenomenon during CO2 flooding in ultralow permeability reservoirs. The deposited asphaltene occupies the pore volume and decreases permeability, resulting in serious formation damage and pore well productivity. It is urgent to investigate the asphaltene deposition mechanisms, adverse effects, and preventive measures. However, few asphaltene deposition investigations have been systematically conducted by now. In this research, the asphaltene precipitation mechanisms and adverse effects were comprehensively investigated by using experimental and numerical methods. To study the effects of pressure, asphaltene content, and temperature on asphaltene precipitation qualitatively and quantitatively, the microscope visible detection experiment and the PVT cell static experiment were firstly conducted. The adverse effects on porosity and permeability resulted from asphaltene deposition were also studied by the core flooding experiment. Secondly, simulation models of asphaltene precipitation and deposition were developed and validated by experimental data. Finally, a case study from Changqing oil field was presented to analyze the asphaltene deposition characteristic and preventive measures. The experimental results showed that the asphaltene precipitation increases with the increased pressure before reaching the minimum miscible pressure (MMP) and gets the peak value around the MMP, while decreases slowly. The asphaltene precipitation increases with the increased temperature and asphaltene content. The variation trend of adverse effects on porosity and permeability resulted from asphaltene deposition is similar to that of asphaltene precipitation under the influence of pressure, asphaltene content, and temperature. The case study shows that the water-altering-gas (WAG) with high injection rate suffers more serious asphaltene deposition compared with the WAG with low injection rate, for the asphaltene precipitation increases as the increased pressure before reaching the MMP. The CO2 continuous injection with high injection rate is the worst choice, for low sweep efficiency and the most severe formation damage. Thus, the WAG with optimal injection rate was proposed to maintain well productivity and to reduce formation damage resulted from asphaltene deposition during developing ultralow permeability reservoirs.

DIGITAL FLUID SAMPLING IN DEEP WATER RESERVOIRS USING RESERVOIR FLUID GEODYNAMICS: THE BEGINNING OF THE DIGITAL FLUID SAMPLING REVOLUTION

Reservoir Fluid Geodynamics (RFG) is a novel thermodynamic methodology that integrates pressure-volume-temperature (PVT), geochemical fingerprinting (GCFP) and reservoir geology with downhole fluid analysis (DFA) data to understand the evolution of reservoir fluids over geologic time. RFG enables the enhancement of reservoir description, estimation of reservoir fluid properties, and optimization of data acquisition plans. Deep-water reservoirs comprise multiple uncertainties in reservoir connectivity, viscous oil and flow assurance. This paper demonstrates the development of digital fluid sampling techniques for deep-water fields using the RFG workflow to predict fluid properties and distribution, to address compartmentalization uncertainties and flow assurance risks, as well as to redefine the well-logging program. Identifying key reservoir concerns is the first step during the implementation of the RFG workflow. Five questions define key reservoir concerns: Do optical density measurements explain the impact of biogenic methane on fluid behavior? Is it feasible to characterize baffling and fault compartmentalization? Can we predict reservoir fluid properties and assess flow assurance risks based on fluid behavior? Is it possible to identify all this in real time? How could we optimize future fluid sampling programs? The next step is to collect the available DFA data and to integrate it with the existing PVT and geochemistry datasets. This paper describes the evaluation of over 150 fluid sampling DFA measurements acquired during the operational history of a Gulf of Mexico field. Fluid behavior and optical density gradients are interpreted from a geological perspective to understand reservoir connectivity. A strong correlation between optical density and asphaltene content enables digital fluid sampling for different PVT and geochemical parameters. Lastly, a general correlation of optical density and asphaltene content is derived for multiple Gulf of Mexico oil fields. Optical density measurements support a consistent characterization of biogenic methane along the studied deep-water field, suggesting a relation to fluid migration and charging from deeper to shallower reservoirs. Likewise, optical density gradients and its integrated evaluation facilitate the identification of mass transport complex (MTC) baffles in the north part of the field and the characterization of fault compartments in the main reservoir sands. In addition, the RFG workflow reveals the difference in fluid behavior of sampled wells located in the area of a water injection project by identifying asphaltene clustering near the oil-water contact. The correlations of optical density and asphaltene content help to predict fluid properties and to estimate its uncertainty, benefiting risk assessment for asphaltenes deposits and flow assurance in deep water operations. Real time analysis of optical density measurements during fluid sampling permits the characterization of fluid properties and reservoir connectivity, optimizing future fluid sampling programs when fluid contamination reaches 10%. Ultimately, this innovative methodology conveys a general correlation to predict asphaltene content based on optical density measurements for deep-water reservoirs in the Gulf of Mexico, enabling the possibility to predict reservoir fluid properties in real time fluid sampling operations.

Deasphalting of Atmospheric Iraqi Residue using Different Solvents

Different solvents (light naphtha, n-heptane, and n-hexane) are used to treat Iraqi Atmospheric oil residue by the deasphalting process. Oil residue from Al-Dura refinery with specific gravity 0.9705, API 14.9, and 0.5 wt. % sulfur content was used. Deasphalting oil (DAO) was examined on a laboratory scale by using solvents with different operation conditions (temperature, concentration of solvent, solvent to oil ratio, and duration time). This study investigates the effects of these parameters on asphaltene yield. The results show that an increase in temperature for all solvents increases the extraction of asphaltene yield. The higher reduction in asphaltene content is obtained with hexane solvent at operating conditions of (90 °C, 4/1 solvent to oil ratio), where the asphaltene yield was 93%. The highest recorded value of API value at 150 ml for all solvents at the highest temperature and duration time; this value is 32 when using n-heptane solvent at 15/1.

Effect of Asphaltene on Threshold Pressure Gradient of Heavy Oil in Porous Media

Many studies have shown that heavy oil with high asphaltene content has a yield stress. Coupled with the solid-liquid interaction between porous media and heavy oil, there is a threshold pressure gradient when heavy oil flows in porous media. Meanwhile, some previous research has indicated that the high viscosity of heavy oil is the decisive factor for its threshold pressure gradient. Hence, this concept needs more clarification, especially because its accuracy is questionable. In this research, different oil samples with the same viscosity and also different asphaltene contents heavy oil samples were prepared. The viscosity of the different heavy oil samples was measured. Threshold pressure gradient experiments under different permeabilities and temperatures were also conducted on heavy oils. The results proved that the viscosity was not directly related to threshold pressure gradient of heavy oil. They also suggested that the heavy oil viscosity increased with the increase of asphaltene content. Moreover, the formula of the factors affecting threshold pressure gradient was regressed, and also its applicability was verified. As the temperature and core permeability increase, the threshold pressure gradient was also proven to decrease significantly. Furthermore, it was found that the threshold pressure gradient increased significantly with the increase of asphaltene content. Therefore, the heavy oil threshold pressure gradient could be characterized as a function of temperature, permeability, and asphaltene content. This study provided some theoretical support for the research attempts on the reduction of threshold pressure gradient and also on the effective development of heavy oil reservoirs.

A Method for Controlling the Process of Dynamic Settling of Oil Emulsion and A Device for Its Implementation

The paper describes a method for controlling the process of dynamic settling of oil emulsion (OE). The method involves measuring the flow rate of oil emulsion at the inlet of the settler, the optical density of the fluid layer along the height of the settler, the water level pressure at three points of the height of the settler. The measured values are used to determine the asphaltene content in the fluid layer along the height of the settler and the level of the water cushion (WC) in the settler. The values of these quantities are compared with their nominal ones ​​and when the WC level deviates upwards, the flow rate of drainage water discharged from the settler is increased, and vice versa, and if the asphaltene content deviates upward, the oscillation frequency or redistribution of the initial OE flow among parallel-working settlers is increased. When determining the asphaltene content in the fluid layer, the height of the settler is taken into account. When changing the oscillation frequency is inefficient, if the asphaltene content in the fluid layer increases, the dosage of the demulsifier is increased and vice versa.