Light Oil Samples Research Articles

Experimental Study on Low-Temperature-Oxidation Parameters and Simulations of Exothermic Process during Air Injection in Light Oil Reservoirs

Summary The thermal development process for light oil reservoirs using air injection technology is to release heat through low-temperature oxidation (LTO) between the injected air and crude oil and gradually increase the reaction zone’s temperature to displace crude oil. However, existing LTO experimental methods for air injection do not adequately capture the characteristics of LTO and struggle to directly obtain LTO kinetic parameters at low temperatures. In this paper, we used light oil samples from the Huabei Oilfield, China, as the studied objects and proposed innovative methods for obtaining and calculating LTO kinetic parameters. Further, we validated the feasibility of the proposed methods through experimental and numerical simulations. The results indicate that the lower limit temperature at which oxidation parameters can be directly measured through the accelerating rate calorimeter (ARC) experiments is 124°C. We matched the calculations from the ARC experiment curve-extension method for kinetic parameters with the results from both the high-pressure thermogravimetric analyzers (HP-TGA) experiment and the ramped thermal oxidizer (RTO) experiment. The fit between these results indicates that three methods are suitable for obtaining LTO parameters and can be used to derive chemical equations for LTO reactions in numerical simulation models. The simulation results from the reservoir scale indicate that, following air injection into the light oil reservoir, the peak temperature at the leading edge of the high-temperature zone reaches 370.9°C. The interaction between crude oil and air remains in the LTO phase, facilitating a sustained thermal accumulation within the reservoir. This study can provide a reference for reservoir development under similar conditions.

Study on Oil Composition Variation and Its Influencing Factors during CO2 Huff-n-Puff in Tight Oil Reservoirs

With immense potential to enhance oil recovery, CO2 has been extensively used in the exploitation of unconventional tight oil reservoirs. Significant variations are observed to occur in the oil’s composition as well as in its physical properties after interacting with CO2. To explore the impacts of oil properties on CO2 extraction efficiency, two different types of crude oil (light oil and heavy oil) are used in CO2 huff-n-puff experiments. Moreover, numerical simulation is implemented to quantitatively inspect the impacts of different influencing factors including production time, reservoir pressure and reservoir temperature on physical properties as well as on the oil composition variation of the crude oil. The findings of the experiments demonstrate that, whether for the light oil sample or for the heavy oil sample, hydrocarbon distribution becomes lighter after interacting with CO2 compared with the original state. In addition, it is also discovered that the hydrocarbon distribution variation is more significant for the light oil sample. The findings of the numerical simulation suggest that production time, reservoir pressure and reservoir temperature have significant impacts on the produced oil composition and properties. The hydrocarbon distribution of the oil becomes lighter with the increasing of production time and formation pressure, while it becomes heavier with the increasing of reservoir temperature. At the very beginning of the oil production, the properties of the produced oil are worsened. Compared with the original state, the oil density and viscosity are 25.7% and 200% higher, respectively. It is suggested that viscosity reducers are added into the well to improve the oil properties in this period. With the continuing of the oil production, the oil properties are continuously promoted. At the end of the simulation time, the oil density and viscosity are 3.5% and 15.1% lower compared with the original oil, respectively. This paper has great significance for the implementation of CO2 huff-n-puff in tight oil reservoirs.

Experimental investigation and thermodynamic modeling of asphaltene precipitation during pressure depletion and gas injection at HPHT conditions in live oil using PC-SAFT EoS

Due to the high costs associated with asphaltene precipitation and deposition, the study of this flow assurance problem has always been a major issue in the petroleum industry. We studied the asphaltene phase behavior in four Iranian live oil samples. First, asphaltene onset pressure and the amounts of the precipitated asphaltene during pressure depletion and gas injection at high-pressure high-temperature (HPHT) conditions were measured, experimentally. Then, thermodynamic modeling of asphaltene precipitation was performed using the perturbed chain form of the statistical associating fluid theory (PC-SAFT). In previous researches, PC-SAFT equation of state (EoS) along with the standard method of characterization was applied to light crude oil having low asphaltene content only, while in this work, three of the samples were heavy oil with high asphaltene content. To perform the thermodynamic modeling, the oil samples were characterized by two different methods. In the first method, the adjustable parameters of the model, which are the aromaticity of aromatics + resins and the aromaticity of asphaltene, were adjusted separately. In the second method, both of the parameters of the model were tuned simultaneously, as one of the novelties of this research. Then the amounts of precipitated asphaltene were modeled using the aforementioned characterization methods, and the results were compared to the experimental data. According to the results, simultaneous adjustment of the model parameters in the heavy oil samples could improve the average absolute deviation (AAD) by 5% - 12%. However, no remarkable improvement was observed for the light oil sample. For two of the oil samples, the proposed model showed a good agreement with the experimental data as the calculated AAD were 14% and 26%. For the other oil samples, the trend of the experimental data was predicted by the model, but the values of the experimental data could not be matched. We were able to solve this problem by introducing a confidence factor for experimentally measured data. By considering this weight factor, in one of the samples, the AAD was reduced by about 70% and reached 24%, and in other oil sample, the error decreased by 90% and reached 31%.

Enhanced Recovery of Light Oil by using Combustion Tube: An Experimental Analysis

ABSTRACT The multitude of chemical compounds in the crude oil and their multiple reactions with oxygen pose serious challenge to the understanding of in situ combustion in porous media. This article describes a combustion tube experiment of a light oil sample of 37°API, and the derivation of an overall reaction stoichiometry from the effluent analysis. The differential scanning Calorimetry and the thermo-gravimetric analysis show the distillation of crude oil at low temperature, and multiple oxidation regimes at higher temperature. In the combustion tube experiment, the injected air could sustain the combustion front at around 550°C. The cumulative flow of oil and brine was monitored with time vis-à-vis the progression of the front. The non-condensable gases at the effluent were analyzed to find the CO/(CO+CO2) ratio and the H/C ratio. Based on the composition of the flue gas, an overall reaction stoichiometry was formulated.

Development of a new scaling model for asphaltene precipitation in light, medium, and heavy crude oils

Asphaltene precipitation adversely affects crude oil recovery and transportation. Hence, a precise determination of asphaltene precipitation is of great importance. Development of a scaling equation by Rassamdana et al. and its modifications have been based on asphaltene aggregation. However, the proposed models/correlations do not consider the contribution of oil characteristics including resin content and API gravity to the precipitation phenomena.The present study aims to propose a modified scaling model for forecasting asphaltene precipitation in three different types of crude oils: light, medium, and heavy oils. The impacts of resin to asphaltene ratio, pressure, dilution ratio, and molecular weight of precipitant (n-alkane) are investigated through conducting experimental and modelling phases. Compared to the previous methods, the key difference of the proposed model is the inclusion of API gravity and resin to asphaltene ratio as additional parameters in the predictive equation, leading to a better estimation. The comparison of the new model with the previously reported models confirms its greater accuracy over a wide range of input parameters for different oil types. The high magnitude of the coefficient of determination (0.98) and low value of mean absolute error (0.06) for all three oil types demonstrate that the proposed model is a robust predictive tool for the estimation of asphaltene precipitation. It was found that a greater amount of asphaltene precipitation in light oil samples is obtained at higher dilution ratio and lower pressure conditions where the lighter diluents are used. In addition, the API gravity and molecular weight of diluents have the greatest influence on asphaltene precipitation.

Research of rheological properties and displacement of high-paraffin oil

One of the urgent problems in the extraction of hard-to-recover reserves (TRIZ) of oil is the formation of asphalt-resin-paraffin deposits (AFS) at oil fields, which entails a number of complications when extracting reserves from the subsoil. In solving the problems associated with the study of the mechanism of deposition of asphalt-resin-paraffin complexes on the downhole equipment or inside the reservoir, the leading role is played by laboratory studies with modeling of objects and conditions inherent in a particular field. In particular, it is necessary to prepare model solutions of hydrocarbons simulating downhole oil containing asphalt-resin-paraffin deposits. The purpose of this work was to establish by an experimental method the dependence of the rheological properties of model oil solutions on the amount of asphalt-resin-paraffin deposits dissolved in it, and to study the efficiency of displacing the prepared model oil solution from the bulk model of core with sodium laurine sulfate. The novelty of the work lies in comparing the effect of the mass content of asphalt-resin-paraffin deposits on the viscosity and density for light and heavy oils and in studying the effectiveness of sodium laurine sulfate when displacing paraffin oil. Several oil solutions were prepared with various mass proportions of ARPD in them, after which the temperature dependence of the viscosity and density of each solution was determined. It has been established that the presence of asphalt-resin-paraffin complexes more strongly affects the density when they are dissolved in light oil. As the mass concentration of paraffin deposits increases, their effect on density decreases for both the light oil sample and the heavy oil sample. The viscosity of the presence of paraffin is much more pronounced if they are dissolved in heavy oil than in light oil. There is a phase transformation point for asphalt-resin-paraffin complexes, which will need to be taken into account when setting up laboratory studies to study the mechanism of deposits of asphaltenes, resins, paraffins in the reservoir or downhole equipment. An experimental method was also used to study the displacement ability of sodium laurinsulfate on a bulk core model saturated with prepared model oil solutions, which are paraffinic oil. It was established that this surfactant has a greater oil displacement efficiency compared to water, in addition, based on the result, it follows that the oil displacement coefficient non-linearly depends on temperature. So, when oil is being displaced with paraffin deposits dissolved in it, there is an optimum temperature at which the maximum oil displacement coefficient is ensured.

Use of real crude oil fractions to describe the high pressure phase behavior of crude oil in carbon dioxide

The knowledge about crude oil phase behavior at high-pressures is a challenge for scientists due to inherent complexity to this systems. Some works employ model systems attempting to predict crude oil behavior, but the results are normally poor. In this sense, the use of real crude oil fractions can be an alternative to improve the accuracy of the models used in these simulations. In this work, a light oil sample has been fractionated to generate four representative fractions. An approach to estimate the critical properties of these distilled fractions using only density and vapor pressure experimental data is presented. In sequence, phase behavior of the pseudo binary (carbon dioxide (CO2)+real crude oil fractions), multicomponent (mixture of fractions+CO2) and original crude oil+CO2 systems were determined using static synthetic method and static synthetic+NIR, with CO2 molar fraction range of 0.367-0.986, temperature range of 20⿿80°C and pressure up to 300bar. Binary interaction parameters (BIP) were estimated for each pair (CO2+distilled fraction) and employed to describe the phase behavior of a CO2+crude oil systems with Peng-Robinson equation of state (PR-EOS) and quadratic mixing rule. The results suggest that the use of real fractions can be a safer strategy for predicting the phase behavior of petroleum in carbon dioxide. Besides, NIR spectroscopy showed to be a good alternative to study phase behavior of dark/opaque systems.

A comparative study of the carbon dioxide and nitrogen minimum miscibility pressure determinations for an Iranian light oil sample

ABSTRACTMiscible gas injection is an approved profitable process that could significantly enhance oil recovery from different types of reservoirs while the major factor affecting its efficiency would be the minimum miscibility pressure (MMP) value. A recent experimental technique, known as vanishing interfacial tension (VIT), can estimate the MMP for gas–oil mixtures by measuring interfacial tension values and extrapolating them to zero at a sequence of pressures. Compositional simulation models are also useful in MMP determination by tuning an equation of state to compute the realistic phase behavior of reservoir fluid. In this paper, the capability and quality of MMP prediction via different methods such as laboratory slim tube tests, VIT technique, compositional simulation, and various empirical correlations were examined using a light oil sample taken from an Iranian carbonate reservoir, employing two pure gases of CO2 and N2 as the injectants. The accuracy and validation of the mentioned methods were then confirmed successfully by obtaining negligible overall absolute deviation percentages (AD%) compared with the conducted slim tube tests results.

Fractal analysis of asphaltene aggregation phenomena in live oils at elevated pressure and temperature

In this work, high-pressure microscopy technique was used to measure the size and fractal dimension of asphaltene aggregates formed in different live oil samples at elevated pressures and temperatures. It was found that the asphaltene aggregates in live oil samples are irregular fractal-like structures with pressure−temperature-dependent fractal dimensions. By monitoring the variation of the fractal dimension and size of the asphaltene aggregates with pressure and temperature, the mechanisms responsible for asphaltene aggregation process at elevated pressures and temperatures can be well predicted. The range of fractal dimension of asphaltene aggregates in live oils is similar to that observed in classical colloidal systems. In light oil sample, depressurization process at lowest temperature (319 K) leads to the formation of large and loose aggregates, that is, porous aggregates with low fractal dimensions in the range from 1.63 to 1.72. With temperature rise, denser and more compact structures are formed with fractal dimensions varied in a narrow range of 1.90–2.01 at highest temperature of 408 K. In heavy oil sample, the fractal dimensions change in a wide range at different temperatures (1.56–1.90 at 368 K, and 1.68–1.89 at 333 K). From a practical viewpoint, the present study provides qualitative and quantitative information on the significance of pressure, temperature, and oil type on the shape/structure, and consequently density/compactness of asphaltene aggregates in live oils at pressure and temperature conditions of oil reservoirs.

A Novel Sulfonated Alkyl Ester Surfactant to Reduce Interfacial Tensions in a Wide Range Salinity with Monovalent and Divalent Ions

A novel sulfonated alkyl ester (SAE) was developed. The sulfonated alkyl ester has unique chemical structures that aimed to combine the advantages of ester-based and sulfonate-based surfactant in one compound. This surfactant was studied for its performance to reduce interfacial tensions in a wide range of salinity with monovalent and divalent ions and in a light and heavy oil samples. The study showed that the sulfonated alkyl ester surfactant gives a good performance in a light oil sample in a high monovalent ion concentration and also give a good performance in a heavy oil sample in both low and high concentration of monovalent and divalent ions solution.

Spectral signature of Egyptian crude oils

Crude petroleum oils are complex mixtures of diverse hydrocarbons, in widely varying compositions, that originate from a variety of geological sources. Fluorescence emission spectra have been measured for two types of Egyptian crude petroleum oil, its light and heavy products over a broad range of excitation and emission wavelengths. Both types of crude oil products are characterized by spectral signatures with a differing topography: the number of fluorescent peaks, their coordinates (λex, λem) on the plane of the three dimensions spectrum, and the shape of the bands formed by the contour line density, changeable in either direction. The refined light oil shows emission spectra at λmax between 350 and 500 nm according to the excitation wavelength. The refined heavy oil shows very broad unstructured emission spectra with λmax > 400 nm. As a group, they could certainly be distinguished from the light oil samples and most of the crude oil.

The Thermodynamic Modeling of Asphaltene Precipitation Equilibrium during the Natural Production of Crude Oil: The Role of Pressure and Temperature

Asphaltene precipitation is a sophisticated issue in the upstream oil industry, worldwide, and has detrimental effect on a verity of production processes; it damages the properties of the reservoir and causes an unfavorable and significant decrease in oil production. In spite of numerous studies to predict asphaltene behavior, the effect of temperature on asphaltene precipitation during pressure depletion at reservoir conditions is still obscure in the literature. In this study the PVT data as well as experimental data of asphaltene precipitation at reservoir conditions of an Iranian light oil samples is used, and the asphaltene precipitation and deposition envelops (APE and ADE) of the oil are developed using solid thermodynamic modeling.

Asphaltene Instability Trends to Predict Asphaltene Precipitation Onset Pressure: Constrained for Light and Heavy Crude Oils

The study investigates asphaltene instability trends (ASISTs), originally developed by New Mexico Tech, for crude oils with different °API gravities and asphaltene contents. Different ratios of precipitants/solvents have been used to construct the ASISTs at ambient conditions. Results were extended to reservoir conditions using routine PVT data. The ASIST method was used to predict the asphaltene precipitation onset pressure at reservoir conditions. Due to the kinetic effect on asphaltene precipitation using the titration method, pressure depletion induced asphaltene precipitation experiments were carried out for the heavy oil sample. Results, using the modified Miller–Flory–Huggins model, were thermodynamically modeled to validate the ASIST observations and for finding an appropriate lag time that can correspond to reservoir conditions. Similar asphaltene precipitation and thermodynamic modeling were adapted from the literature for the light oil sample. Results suggest that, for the light oil sample, 5 hours is appropriate lag time to perform ASIST, which is in agreement with the reported trends; for the heavy oil sample, however, results suggest that even a 5 hours lag time is not short enough for the titration experiment so that it can be kinetically extended to asphaltene precipitation in the reservoir. We suggest a 1 hour lag time for the samples with low °API gravities and high asphaltene contents. More case studies from different crude oils from different geological settings are required to draw any rigid kinetic framework for the ASIST.

Thermodynamic Investigation of Asphaltene Precipitation during Primary Oil Production: Laboratory and Smart Technique

Asphaltene precipitation (AP) is recognized as a complicated occurrence that results in weakening reservoir characteristics and subsequent considerable decline in oil production rate. Asphaltene instability occurs due to variations in thermodynamic properties such pressure, temperature, and mixture composition. AP prediction is an important design factor in implementation of any enhanced oil recovery (EOR) process. In this study, experiments were conducted using some light oil samples to measure important phase behavior properties such as the bubble point pressure (BPP) and the amount of precipitated asphaltenes. A thermodynamics model was also developed to determine equilibrium compositions of the oil samples, considering AP. Then, potential application of a feed-forward artificial neural network (ANN) model, optimized by the imperialist competitive algorithm (ICA), was proposed to estimate BPP and the amount of AP. Comparison between the ICA-ANN predictions and the experimental data shows that the avera...

Evaluation of different extraction procedures for determination of organic Mercury species in petroleum by high performance liquid chromatography coupled with cold vapor atomic fluorescence spectrometry

An extraction procedure for extracting organic mercury species including methylmercury (MeHg) and ethylmercury (EtHg) from petroleum samples was developed. Three extraction methods (shaking, ultrasonic and microwave assisted extraction) using different extraction solvents (TMAH, KOH/CH3OH, HCl and acidic CuSO4/KBr) were investigated by comparing the extraction efficiency of the organic mercury species. Microwave assisted extraction at 60W for 5min using TMAH (tetramethylammonium hydroxide, 25%, m/v) provided the most satisfactory extraction efficiency for MeHg and EtHg in petroleum at 86.7%±3.4% and 70.6%±5.9%, respectively. Speciation analysis of mercury was done by on-line coupling of high performance liquid chromatography with cold vapor generation atomic fluorescence spectrometry (HPLC-CV-AFS). The proposed method was successfully applied to analyze several crude oil and light oil samples. The concentrations of MeHg ranged from under detection limit to 0.515ngg−1, whereas EtHg was not detected in the samples. This method can be a very useful tool in evaluating the risk of mercury emissions from petroleum.

Monitoring of asphaltene precipitation: Experimental and modeling study

Preparing relatively complete collections of experimental data on asphaltene precipitation in different reservoir conditions leads to considerable improvement in this area of science. In this work, asphaltene precipitation was studied upon two Iranian live oil samples, one a heavy oil and another light oil, under primary depletion as well as gas injections. Pressure depletion experiments were carried out at different temperatures to observe temperature effect besides pressure changes on asphaltene phase behavior. CO 2, dry and enriched gases were used as injecting agents to investigate the effect of different gases on asphaltene precipitation. Surprisingly, it was observed that raising temperature decreases the amount of precipitation in case of heavy oil while acting in favor of precipitation for light oil sample. In addition, Enriched gas resulted in more precipitation compared to dry one while CO 2 acted as hindering agent for light oil samples but increased the amount of precipitation in case of heavy oil. In the next part of this work, polydisperse thermodynamic model was developed by introducing an asphaltene molecular weight distribution function based on fractal aggregation. Modification that was introduced into polydisperse model not only solved the instability problem of Kawanaka model but also eliminates the need for resin concentration calculation. Flory–Huggins and Modified Flory–Huggins thermodynamic solubility models were applied to compare their predictions with proposed model.

Aromatic hydrocarbons as indicators of origin and maturation for light oils from Panyu lower uplift in Pearl River Mouth basin

Aromatic fractions of six light oils and two source rock samples from Panyu (番禺) lower uplift of Pearl River Mouth basin were analyzed using GC-MS (gas chromatography-mass spectrometric) technique. Thirteen aromatic series of hydrocarbons detected such as biphenyls, naphthalenes, phenanthrenes, dibenzothiophenes (more than two hundred aromatic hydrocarbon compounds) were used to analyze the origin and maturity of the light oils. This study indicates that the distribution of aromatic hydrocarbon compounds in the light oils of wells L1 and P1 differs from those of wells P2, P3 and P4. The light oil samples from wells L1 and P1 contain more dibenzofuran and fluorence hydrocarbons and less naphthalene hydrocarbons. The contents of fluorene, dibenzothiophene and dibenzofuran in the two groups of light oils also show their difference in sedimentary environment. Moreover, the diversity of the relative distributions of biphenyl and naphthalene is apparent between the two groups of light oils. As mentioned above, the origin of the light oils from wells L1 and P1 varies from that of wells P2, P3 and P4. According to the result of oil-source correlation, the light oils from wells P2, P3 and P4 mainly originated from the source rocks in the Enping (恩平) Formation. Accordingly, the light oils from wells L1 and P1 may have been derived from the lacustrine shales in the Wenchang (文昌) Formation or from the mixed source of the Wenchang Formation and the Enping Formation. Applying maturity parameters of methylnaphthalenes, methylphenanthrenes and methyldibenzothiophenes from the aromatic hydrocarbons to the study of the maturity of light oils from Panyu lower uplift indicates that the maturity has reached the high mature stage.

Chemically Assisted Ignition Technologies for a Light Oil Air Injection Process

Abstract A light oil (API 30 º) reservoir is an excellent candidate for high pressure air injection, but the oil is not believed to be capable of self-ignition at the reservoir temperature. Several chemical additives and catalysts are studied to evaluate their effectiveness of ignition improvement for this light oil sample. Pressurized Differential Scanning Calorimetry (PDSC) and Accelerating Rate Calorimetry (ARC) experiments are examined in this study. The oil sample, which is mixed with certain catalysts and chemical additives, is subjected to a controlled heating schedule under a constant flow rate of air at 4.14 MPa (600 psig) and 13.8 MPa (2,000 psig) pressure for the PDSC and ARC tests, respectively. The amount and rate of heat released by the oxidation reactions is analyzed for those tests. In the presence of a metallic catalyst and chemical initiators, oxidation behaviour of the oil tested is dramatically improved. Also observed are a significant reduction in the onset temperature of significant exotherm and an increased rate for the release of heat. Introduction Air injection has been proven as a viable process in improving oil recovery from light oil reservoirs, and as a result, it has received much interest in recent years(1, 2). The concept of recovery increment is when air is injected into a light oil reservoir and exothermic chemical reactions occur. The desired reactions result in heat generation and the production of carbon dioxide. Downstream of the reaction zone, the combustion produced gas sweeps oil toward the production wells, combining with light hydrocarbon fractions vapourized by heat released from oxidation reactions. Therefore, incremental oil production is achieved. However, air injection for a light oil reservoir is a complex process involving simultaneous heat and mass transfer in a multiphase environment coupled with oxidation chemical reactions. Ignition is the first phase of this process and a satisfactory ignition is of prime importance in initiating a successful air injection process(2). In high temperature reservoirs, the air injection process is initiated by injecting air, which may spontaneously ignite the oil-in-place(1). However, in some cases, spontaneous ignition of the reservoir oil is not likely to occur so that several artificial means have been implemented(3), including down hole electrical heaters, a gas burner or injection of steam, but it is highly desirable to avoid having to run heaters or burners when air injection is to be applied in deep, high pressure reservoirs. As a result, chemical ignition is proposed(2). The concept of chemical ignition is where a slug of chemicals with reactive oxidation characteristics is injected into an oil bearing zone prior to the injection of air from an injector. If heat released from an oxidation reaction is continually generated at a rate greater than it is dissipated, starting at the native reservoir temperature, oil can be spontaneously ignited without the application of artificial means. The reactive nature of the base oil present in the ignition zone can be enhanced or stimulated. A spontaneous ignition may occur within the formation. Bednarski(4) reported on a chemical ignition improvement experiment.