The Determination of Effective Diffusivity Coefficients in a Solvent Gas Heavy Oil System for Methane

Abstract

In this investigation, an accurate high pressure and temperature diffusion setup was applied to measure the diffusion coefficients of methane in Iranian heavy oils in presence and absence of porous media by using the pressure-decay method. The solvent diffusivity in heavy oil was determined by both graphical and numerical methods. In addition, the effects of the porous medium and the temperature on the molecular diffusion coefficient of the solvent gas in the liquid phase were discussed and finally, using experimental data, a functionality dependence of molecular diffusivity on temperature and porous medium characteristics was proposed.     

Wax Diffusivity: Is It a Physical Property or a Pivotable Parameter?

Abstract

In order to predict wax deposition problems the key parameter is the wax diffusion coefficient. While it is quite easy to find measured diffusivity values for well-defined compounds at quite low concentrations, very few experimental data are available for wax diffusivity in oil. Most of the literature data are estimated by interpolating experimental data obtained by loop tests and then they are affected by a noticeable uncertainty. In fact this parameter collects the whole uncertainty of the test and the paradoxical situation is that the key parameter ends to be the most error-affected or to be used as a pivotable parameter in “predictive” models. This article describes an experimental procedure to determine the overall diffusivity coefficient of waxes into the oil; the main advantage of this technique is that it allows the direct measure of diffusivity on the oil. Besides it is a very simple and straightforward technique. Results obtained were used to gain insight into the deposition process; the conclusion was that, due to the counter-intuitive diffusivity dependence on temperature, it is likely that noncompositional models available at present are structurally incorrect.     

Empirical Statistical Correlation for Estimating Solubility of Natural Gas in Crude Oil

Abstract

A formula for natural gas solubility in crude oil is developed. The correlation is function of pressure and temperature. Good results are obtained with average absolute percentage error 4.4% for 27 data points. This formula is valid for pressure of 4,900 psi and temperature range 188°F–256°F.     

Oil:Oil Correlation for Some Oil Fields in the North Western Part of the Western Desert,Egypt

Abstract

Physical and specific geochemical analyses are used in detail for the petroleum geochemical studies to permit the correlation of six crude oil samples from Western Desert Egypt. Different analytical techniques, including liquid chromatographic separation, gas chromatography, and gas chromatography-mass spectrometry (GC-MS), were used to characterize the oil samples. The oils were identified using oil characterization parameters including specific gravity (°API), sulfur content, distribution of n-alkanes, carbon preference index (CPI), pristane/phytane ratio, isoprenoid/n-alkane ratios, and detailed biological marker analysis. All these parameters showed that the studied oil samples are correlated with each other, where they are similar in their oil type maturation and source depositional environments.     

TWO-DIMENSIONAL SOLUBILITY PARAMETER MAPPING OF HEAVY OILS

ABSTRACT

The solubility and insolubility of heavy oils and their fractions in dilute mixtures with various solvents were used to characterize heavy oil interactions. A two-dimensional solubility parameter, developed for the selection of solvents for organic polymers, was found to group all the solvents for each heavy oil fraction in polygon areas when the complexing solubility parameter component was plotted against the field force solubility parameter component. All fractions of Cold Lake vacuum residua, except for the saturate fraction, form concentric solubility areas. Therefore, in going in the direction of decreasing aromaticity from coke to asphaltenes to resins to aromatics, all solvents for the previous fraction in the series are also solvents for all subsequent fractions in the series. As a result, asphaltenes can be precipitated, but not extracted, from heavy oils. This is attributed to the interaction among polynuclear aromatics being the dominate interaction in petroleum that causes insolubility in hydrocarbon liquids. However, the paraffinic chains on the same petroleum molecules limit their solubility in highly complexing liquids. In contrast, even vacuum gas oils from the Exxon Donor Solvent coal liquefaction process are insoluble in aromatic liquids but soluble in moderately complexing liquids because of hydrogen bonding, resulting from oxygen functionality. Hydrotreating of these coal derived vacuum. gas oils reduces their oxygen functionality and increases their solubility areas so that they become compatible with petroleum liquids.     

The Effective Diffusion/Dispersion Coefficient in Vapor Extraction of Heavy Oil

Abstract

In this study, a new correlation for determination of effective diffusion/dispersion coefficients in the vapor extraction of heavy oil/bitumen (VAPEX) is introduced. This model takes into account the solvent concentration as well as the drainage height and permeability dependency of these coefficients. The concentration dependency in this model stems from the mixture viscosity changes, while the height dependency appears directly in the correlation. The correlation was obtained using the experimental results of the VAPEX experiments that were conducted with physical models of varying sizes and different permeability sand-packs. Estimation of a proper mass transfer coefficient has been a challenging issue for the analytical and numerical simulation of the VAPEX and other similar processes. Incorporating the effect of drainage height on dispersion with a concentration-dependent diffusivity model enables one to estimate the dispersion coefficient values involved in this process.     

Spontaneous imbibition of water into cylindrical cores with high aspect ratio: Numerical and experimental results

Spontaneous imbibition of water into oil-saturated porous chalk having a cylindrical shape with the top and bottom faces closed for fluid exchange was modeled by solving a diffusion-like equation with the assumption of constant capillary diffusivity coefficient (CDC). The calculated oil recoveries vs. time curves have the same shape as the experimental curves and fit them very well over the whole saturation range. Furthermore, the analytical solution of the diffusion-like equation describes water saturation profiles, which are in qualitatively agreement with results reported in the literature. The model presented is able to account for different wettabilities of the rock material due to variations in the capillary diffusivity coefficient. The model is a useful tool when analyzing oil recovery rates measured from cylindrical cores in the laboratory.     

An Experimental Study of Secondary WAG Injection in a Low-Temperature Carbonate Reservoir in Different Miscibility Conditions

Abstract

This experimental study is aimed at evaluation of the performance of secondary WAG injection in carbonate cores at different pressures. To do so, a comprehensive series of high-pressure high-temperature (HPHT) core flooding tests are conducted. The fluid system includes reservoir dead and live crude oil, CO₂, and synthetic brine while the chosen porous media consists of a number of fractured carbonate core samples. Parameters such as oil recovery factor, water and oil production rates, and pressure drop along the core are recorded for both dead and live oil. According to results, at first increasing pressure improves the oil recovery, but this improvement after MMP is not as significant as it is before MMP. Also recoveries of dead and live oils at same pressure show different values due to differences in miscibility condition of injected gas. Then as the graphs demonstrate, relative permeability reduction due to hysteresis effect has dominant effect on pressure drop curves. Finally, as the production rate curves show, nearly all of the remained oil after breakthrough is produced as the gas is being produced and almost no oil can be recovered during water production portions.     

Mutual Interactions of CO2/Oil and Natural Gas/Oil Systems and Their Effects on the EOR Process

Mutual interactions between oil and gas are critical factors affecting the gas enhancing oil recovery (EOR) process. Focusing on CO₂/oil and natural gas/oil systems, their interactions are researched and compared by extraction capacity and solubility measurement experiments. Core flood tests are also implemented to determine the effects of interactions on oil recovery. Results show that CO₂ can extract more light oil from the original and its extraction efficiency can reach 59.3% at 46 MPa, whereas that of natural gas is only 7.3%. However, heavy components content and viscosity of the residual oil processed by CO₂ increases significantly because of extraction, while natural gas does not affect the composition of the residual so remarkably. With increased pressure, solubility of CO₂ and natural gas in a light oil present a linear growth trend with similar rate, but the former is greater than the latter by about 130m³/m³. Core flood tests show that, for the continuous gas injection in the secondary oil recovery process, recovery of CO₂ flood is about 20% higher than that of natural gas due to the late breakthrough of CO₂, as most of the crude oil is produced before breakthrough.     

Modeling of Asphaltene Phase Behavior with the SAFT Equation of State

Abstract

The SAFT equation of state was used to model asphaltene phase behavior in a model live oil and a recombined oil under reservoir conditions. The equation of state parameters for the asphaltenes were fit to precipitation data from oil titrations with n-alkanes at ambient conditions. The SAFT model was then used to predict the asphaltene stability boundaries in the live oils. A lumping scheme that divides the recombined oil into six pseudo-components based on composition, saturates–aromatics–resins–asphaltenes fractionation, and gas–oil-ratio data was introduced. Using this lumping scheme, SAFT predicted stock-tank oil and recombined oil densities that are in excellent agreement with experiment data. For both the model and the recombined oil systems, SAFT predicted asphaltene instability and bubble points agree well with experimental measurements.     

DETERMINATION OF HYDROCARBON GROUP TYPES IN MIDDLE DISTILLATES A modification proposed Tor method IP -391/95

ABSTRACT

The IP391/95 method using high performance liquid chromatography (HPLC) with refractive index detection, has been utilized to determine hydrocarbons group type (saturates, monoaromatics, diaromatics and polyaromatics) in middle distillates. A modification to this method is proposed involving the use of hydrocarbon group type concentrates separated using liquid chromatography as standards in place of single compound and use of area % and response ratio in lieu of area, slope and intercept has been investigated. The results from the above two approaches are compared with standard IP391/95 as well as with the gas oil of known composition prepared by mixing hydrocarbon concentrates. The results from above comparison suggested that the data derived using hydrocarbon group type concentrates was reliable. Appreciable difference was not observed in data derived using area percent response ratio and area slope intercept. The former method was suggested for regular use, as repeatability of area percent was better than the data based on area. The data generated by both the original and modified procedure for a set of five gas oil samples obtained from different sources have been compared and a difference of 0.5-6.5% w/w in saturates. 1.0-3.2% w/w in     

Flow Properties of CO2/Crude Oil in Miscible Phase Flooding

Abstract

The high-temperature and high-pressure three-dimensional (3D) device is used to study miscible flooding of CO₂ and crude oil. The experiment model is a real sand plate. In oil reservoir condition, there is a large difference between production and injection volume. The complex flowing characteristics of CO₂ flooding in pore media are observed in recovery, water cut, and gas–oil ratio curves. By analyzing the water saturation contour plot measured by a saturation probe, CO₂ and oil can be miscible. The viscosity of miscible liquid and flowing pressure decreases. This is the important mechanism of enhanced oil recovery. When the viscosity of miscible liquid and flowing pressure decreases, miscible CO₂ and oil contacted with water can make a similar three phase. This is the important mechanism of enhanced oil recovery. Based on the conclusion, the main reason for the production and injection difference is that high-density CO₂ would flow into pore media in which water and oil cannot flow.     

Identification of Hydrocarbon Movability and Type from Resistivity Logs

Abstract

Resistivity data is normally used to evaluate water saturation using porosity values from porosity logs (neutron and density). Determination of initial oil (gas) in place is based on hydrocarbon saturation, porosity, and thickness obtained from openhole logging data for a given drainage area. It is important not only to determine the initial hydrocarbon in place, but also to define the existing hydrocarbon movability, indicating the recoverable hydrocarbon and its type. This article presents a new approach of the hydrocarbon movability factor (HCM). This factor is derived from shallow and deep resistivity data. The relation F = a/φ ^m is correct in water-saturated zones; in partially saturated zones this relation becomes invalid, and it will give the apparent formation resistivity factor (Fa). Based on this idea, the HCM has been derived, with scale going from 0.0 to 1.0. It is found that for HCM less than 0.75, hydrocarbon is movable, and for HCM greater than 0.75, the hydrocarbon is immovable. When HCM is less than 0.25, the movable hydrocarbon is gas, and for HCM greater than 0.25 and less than 0.75, the movable hydrocarbon is oil. Field examples have been analyzed with the HCM factor. These field examples demonstrated the contribution of HCM in the field of hydrocarbon type identification and determination of hydrocarbon movability from openhole resistivity logging.     

Investigating Geochemical Characterization of Asmari and Bangestan Reservoir Oils and the Source of H2S in the Marun Oilfield

Abstract

Geochemical evaluation is one of the most important and applicable methods for optimization of hydrocarbon exploration and production. In this article, the geochemistry of Asmari and Bangestan reservoir oils of Marun oil field was experimentally studied. Marun oil field is one of the giant oil fields in southwest Iran and has two oil reservoirs (Asmari and Bangestan) and one gas reservoir (Khami). The main goal of this study is to investigate the genetic behavior of the above oil reservoirs, focusing mainly on hydrogen sulfide pollutants. Biomarkers of saturated and aromatic fractions were studied on five polluted, three unpolluted Asmari, and two Bangestan reservoir oils. A triangular diagram was used to determine the chemical composition of the studied oil. The results show relatively higher oil maturity for both reservoirs with no biodegradation. The carbon preference index of both reservoir oils was also around 1, which indicates mature oil samples. The pristane-to-phytane ratio, Pri/nC₁₇ versus Phy/nC₁₈, terrigenous/aquatic ratio (TAR), and geochemical data all show that the source rock for both Asmari and Bangestan reservoirs is the same. This source rock was deposited in a reducing environment with algae (kerogen type II) organic matter and without any higher plants. Genetic potential studies of probable source rocks, by means of Rock-Eval VI analysis in Marun oilfield, present Kazhdomi and Garu as main source rocks. Biomarkers of sulfur compounds and structural analysis of Marun oil field revealed that hydrogen sulfide gas pollution in the Asmari reservoir originated from the Bangestan reservoir. In addition, thermal sulfate reduction was a possible main process for hydrogen sulfide formation.     

Oxidative Degradation of Athabasca Bitumen,Fuel Oil,and Used Transformer Oil

Abstract

Oxidative cracking of bitumen, waxy fuel oil, and used transformer oils were carried out individually in an autoclave with 0.6 wt% of hydroquinone as a catalyst. The cracking process is conducted at 410°C in an atmosphere of oxygen gas of 0.15 MPa, for 30 min. The identification and quantitative determination of both the liquids and gases obtained during the cracking process are achieved using packed and capillary gas chromatography (GC) connected with suitable detectors. It was found that the degraded liquid products obtained have a higher percentage of lower hydrocarbons compared to the original feed stocks. Several analytical parameters including API gravity, calorific value, viscosity, density, pour point, etc., were used to evaluate the liquid product obtained. Also, the calorific values of the liberated gases were calculated and compared with that of natural gas. The cracked oil products were distilled and compared to their corresponding petroleum fractions. The cracked fractions have the same characteristics as their corresponding petroleum fractions with the exception of some properties that depend on the aromatic, naphthenic, and waxy nature of the virgin oil.     

The Areal Sweep Efficiency of the First-contact Miscible Displacements: An Experimental Approach

Abstract

Solvent flooding using the water alternating gas (WAG) technique is very important for predicting the process performance. This technique has been employed in a number of oil fields. However, little data are available in the literature. Therefore, there is an immense need for the sweep efficiency data resulting from first-contact miscible flooding, particularly in view of conducting reservoir simulation studies. In this article, we conducted a series of WAG displacements through glass bead packs. A number of miscible WAG displacement tests were conducted at WAG ratios of 1:1, 1:2, and 2:1. Constant flow rates were used to mask the effects of capillary number on sweep efficiency. Experimental results revealed that the WAG ratio affects the sweep efficiency of the miscible flooding process. In addition, new correlations of areal sweep as function of mobility ratio at various WAG ratios were developed. The data provided can be useful to the oil industry in conducting analytical and numerical modeling studies of miscible WAG processes.     

Frictional Heating or Frictional Cooling,That Is the Question

Abstract

The frictional heating and frictional cooling mechanism is first discussed briefly in the present article. A general equation has been developed for predicting the inversion curves—where neither frictional heating nor frictional cooling occurs—for any types of natural gas. The predicted inversion curves can be applied to determine whether frictional heating or frictional cooling happens for any type of gas under a specific set of reservoir and well flow conditions.     

EMPIRICAL APPROACH FOR THE DIAGNOSTIC ANALYSIS OF CHEMICALLY RELATED OIL YIELD LOSSES DURING THE RETORTING OF OIL SHALE

ABSTRACT

The analysis of chemically related oil yield losses during the retorting of oil shale is important for understanding the chemistry of a process, supplying data for modeling efforts and process control of a production facility. Previously developed gas chromatographic correlations for evaluating oil yield losses were duplicated using combined gas chromatograph/mass spectrometric data. Evaluation of these results through calculation of local oil yields indicated that they were higher than expected when compared to material balance oil yields.

A new correlation was developed to estimate the fraction of oil lost by cracking plus combustion. The approach to the new correlation was based on selection of steranes and pentacyclic triterpanes as the species in shale oil which would undergo cracking and combustion to yield selected aromatic compounds. Evaluation of the results from this correlation for determination of local oil yields was found to produce acceptable results.

The two approaches for estimating the fraction of oil lost by cracking plus combustion are compared. The differences appear to be that the earlier approach is dependent upon severe cracking and combustion conditions. The new approach for determining the fraction of oil lost by cracking plus combustion appears to be applicable to a wider range of process conditions and therefore is more useful in research.     

Modeling of Two-Phase Flow in Oil Wells Using a Simplified Two-Fluid Model

Abstract

In this work, with the idea of finding a simplified, numerically stable, one-dimensional, time-dependent two-fluid mathematical model whose predictions are in agreement with oil wells data, a study of the accumulative terms effect on the numerical stability and predictions of a general two-fluid model, was carried out. The fluids considered in oil wells were water, oil, and gas. The liquid phase in the model is formed by water and oil with pseudoproperties. The model is able to predict pressure, volume fraction, velocity, and temperature for both phases. The numerical solution of the model, which consists of mass, momentum, and energy conservation equations, is based on the finite difference technique in the implicit scheme. The thermodynamic and transport properties of the fluids are estimated by black-oil PVT correlations. It was observed that, a numerically stable model, with acceptable predictions has to take into account the accumulative terms for the liquid volume fraction, gas velocity, and liquid temperature. Numerical results are in agreement with field data and theoretical results reported in literature.     

Prediction of Density and Solubility Parameter of Heavy Oils and SARA Fractions Using Cubic Equations of State

Abstract

In this research, the density of the components of some crude oil samples, analyzed based on the Saturates, Aromatics, Resins, and Asphaltenes (SARA) method, has been estimated by Peng-Robinson (PR), Soave-Redlikh-Kwong (SRK), and new equations of state (EOS). The obtained results from the New EOS have been compared with those values obtained by PR and SRK, which showed better compatibility with the experimental data available. Then, the density and the solubility parameters of a different crude oil sample were estimated by the New EOS.