Petroleum Fluids Research Articles

Molecular fingerprint from plant biomarkers in Triassic-Jurassic petroleum source rocks from the Dampier sub-Basin, Northwest Shelf of Australia

Abstract Distinctive land plant biomarker distributions have been described for Triassic-Jurassic source rocks in the Dampier sub-Basin, Northwest Shelf of Australia. Proxies like the higher plant parameter [HPP = retene/(cadalene + retene)] cannot be applied to describe palaeoclimate globally; in fact, the HPP showed similar values (∼0.8) for Triassic and Jurassic source rocks despite the difference in sea level. The higher plant fingerprint [HPF or relative distribution of retene, cadalene and 6-isopropyl-1-isohexyl-2-methylnaphthalene (ip-iHMN)], however, represents a potential discrimination tool for source rock intervals. Here, we name this proxy as plant fingerprint (PF) since our investigation supports a non-vascular plant origin for ip-iHMN. The most distinctive patterns in the PF are found in the Early Jurassic with a predominance of cadalene (∼65%) in an arid climate, and the Middle Jurassic with a predominance of retene (∼70%) during a climate recovery under more humid conditions. Petroleum fluids from the Dampier sub-Basin are cadalene-dominated compared to fluids from the Barrow sub-Basin, which are retene-dominated. We emphasise that the present approach has only local implications and the parameters used herein (including the higher plant parameter or HPP) cannot lead to interpretations at a global scale.

Using polar nitrogen-, sulphur- and oxygen-compound compositions from ultra high resolution mass spectrometry for petroleum fluid assessment in the Eagle Ford Formation, Texas

Using polar nitrogen-, sulphur- and oxygen-compound compositions from ultra high resolution mass spectrometry for petroleum fluid assessment in the Eagle Ford Formation, Texas

Isotope heterogeneity in ethyltoluenes from Australian condensates, and their stable carbon site-specific isotope analysis

Low-molecular-weight (LMW) aromatic compounds from petroleum fluids have not been widely studied for fluid-source correlations due to their volatility and their relatively low abundances in source rocks. However, LMW aromatics are important components in fluids, including condensates which lack biomarkers (molecular fossils typically used for correlation studies). Here, we have investigated the distribution of ethyltoluenes (o-ET, m-ET and p-ET; ortho, meta and para, respectively) in fluvial-deltaic condensates which contain relatively high abundances of the meta-isomer. The meta-selectivity found in these petroleum fluids is consistent with a mineral catalytic effect on the molecular distribution of these compounds, as it occurs during the clay-catalyzed synthesis of ethyltoluenes. Isomers differ up to 6‰ in δ13C values. Condensates from the Northern Carnarvon Basin, North West Shelf of Australia (NWS), have been analyzed by compound specific isotope analysis (CSIA) by GC-ir-MS, and site-specific isotope analysis (SSIA) using a Q-Exactive-GC Orbitrap™-based mass spectrometer. The SSIA revealed a 13C enrichment at the methyl end of the ethyl branch of m-ET, following a normal kinetic isotope effect during thermal maturation (cleavage). Continuous development of this first SSIA application will make possible high resolution analysis of light aromatics to outline the evolution of the organic matter to hydrocarbons in petroleum systems.

Diamondoids as tracers of late gas charge in oil reservoirs: Example from the Tazhong area, Tarim Basin, China

Significant petroleum resources occur in the Ordovician carbonate reservoirs of the Tazhong area (Tarim Basin, China) in accumulations of black oil, volatile oil and condensate. However, the factors controlling the distribution of pools with different fluid phases remain poorly understood. Here, we integrate geological and conventional oil/gas geochemical data with an extensive dataset on diamondoids and propose a model for the occurrence of petroleum fluids in the area. Oils in the study area contain low variety and concentration of diamondoids and organic-sulfur compounds (OSCs) and have oil-dissolved wet gas mostly co-generated with oil. In contrast, liquids in the condensate reservoirs are significantly enriched in various types of diamondoids and OSCs, and have dry associated gas with methane enriched in 13C and relatively high content of H2S. We interpret that mature gas from deeper Cambrian strata, likely generated from thermally cracked oils and affected by thermochemical sulfate reduction (TSR), invaded the condensate reservoirs. Black oil reservoirs did not receive this late gas charge and this preserved their oil phase. The 1D burial history models and data on fluid inclusions suggest that oil charged all studied Ordovician reservoirs in the Late Permian – Triassic time, while the late gas charge occurred in selected reservoirs in the Late Himalayan time (∼10 Ma). Diamondoids proved to be useful indicators of the late gas charge as their variety and concentrations in liquids from the study area show good correlation with the extent of gas invasion.

Molecular simulation of the constant composition expansion experiment in shale multi-scale systems

The phase behavior of hydrocarbons in shale reservoirs has garnered increasing attention in the petroleum industry. Significant differences in the phase behavior of petroleum fluids between conventional reservoirs and shale reservoirs have been observed. Because of the existence of nano-scale porous media in shale reservoirs, there are substantial surface fluid interactions that can lead to a heterogeneous distribution of molecules and an alteration of the fluid phase behavior. In this work, for the first time, we use molecular simulations to investigate the confinement effect on the phase behavior of reservoir fluids in a multi-scale (nano-scale + macro-scale) media. The model has a confined region that mimics the nano-scale porous media and a bulk region that represents the macro-scale porous media (macropores and fractures) in shale reservoirs. For the first time, we use the Gibbs ensemble Monte Carlo (GEMC) simulation at imposed pressures to simulate the constant composition expansion (CCE) experiment for multi-component hydrocarbon mixtures in a multi-scale porous media. Our results show that because of the confinement effect, the composition of the bulk and the confined regions differ significantly. In our molecular simulations, the composition of the lighter components in the bulk region increases, while heavier components are mainly trapped in the confined region. These changes in the composition cause a significant shift or disappearance of the saturation pressure in the bulk region of the multi-component multi-scale hydrocarbon systems.

Variations of diamondoids distributions in petroleum fluids during migration induced phase fractionation: A case study from the Tazhong area, NW China

Diamondoids, resistant to thermal and biological destruction, are useful in identifying the genesis and alteration history of petroleum fluids, especially for condensates in which conventional biomarkers are of trace amounts. Tremendous condensate resources have been discovered in the Ordovician carbonates from the central Tarim Basin, however, the complex genesis and distribution of the condensates have brought challenges in effective exploration and fluid prediction. In this study, the GC × GC-TOFMS analyses were applied on several condensate oil samples. Results showed great variance in the distribution and absolute concentration of diamondoids. Accompany the integrated geochemical and geologic analyses, the studied condensates are ‘daughter’ condensates generated from the similar ‘parent’ condensates that have undergone severe phase fractionation induced by migration. Phase fractionation led to the constant loss of vapor fractions and enriched heavy fractions in the residual condensates during the migration of petroleum fluids towards structural highs. Accordingly, diamondoids were preferentially enriched in shallower condensates and depleted in residual condensates, such variations of diamondoids distributions are attributed to phase fractionation because diamondoids with different molecular sizes differ in the solubilities in vapor phase. This will bring insight into the genesis of secondary condensates and the evaluation of the fractionation extent of petroleum fluids, with which effective petroleum exploration and prediction can be obtained.

Modelling of petroleum multiphase flow in electrical submersible pumps with shallow artificial neural networks

ABSTRACTThis paper first investigates existing empirical models which predict head or pressure increase of two-phase petroleum fluids in electrical submersible pumps (ESPs); then, proposes an alternative model, a shallow artificial neural network (ANN) for the same purpose. Empirical models of ESP are widely used; whereas, analytical models are still unappealing due to their reliance on over-simplified assumptions, need to excessive extent of information or lack of accuracy. The proposed shallow ANN is trained and cross-validated with the same data used in developing a number of empirical models; however, the ANN evidently outperforms those empirical models in terms of accuracy in the entire operating area. Mean of absolute prediction error of the ANN, for the experimental data not used in its training, is 69% less than the most accurate existing empirical model.

Geochemical factors controlling the phase behavior of Eagle Ford Shale petroleum fluids

Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C7+ fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval Tmax release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.

Effect of Low-Concentration of 1-Pentanol on the Wettability of Petroleum Fluid-Brine-Rock Systems.

High-concentration brines generally cause the wettability of petroleum fluid-brine-rock systems to become less water-wet (more oil-wet). The addition of alcohols to the brine, however, may produce an opposite effect. In this work, we investigate the synergic effects of a low concentration of 1-pentanol and brines on the wettability of petroleum fluid-brine-rock systems. The variables examined include the mineral type (mica, quartz, calcite), brine concentration (0-3 M), ion type (monovalent and divalent), crude oil (samples from sandstone and carbonate reservoirs), and 1-pentanol concentration (0.5 and 1 wt %). Adding 1 wt % 1-pentanol to the brine only slightly affects the wettability of a petroleum fluid on sandstone-like mineral surfaces (mica and quartz), whereas the effect is significant for carbonate-like mineral surfaces (calcite). A maximum reduction of 80° in contact angle (measured through the brine phase) is observed at 0.1 M NaCl and 0.5 wt % 1-pentanol. ζ-Potentials of both brine-petroleum fluid and brine-rock interfaces are found to be insensitive to the presence of 1-pentanol in the brine. Based on these observations, we propose that the accumulation of 1-pentanol in the thin brine film confined between the petroleum fluid and the rock surface results in a significant change of the wettability. Our finding may have various practical applications, one of which is the use of a low concentration of 1-pentanol for improving oil production.

Geochemical Characteristics of Oil from Oligocene Lower Ganchaigou Formation Oil Sand in Northern Qaidam Basin, China

Oil from the Oligocene oil sands of the Lower Ganchaigou Formation in the Northern Qaidam Basin and the related asphaltenes was analyzed using bulk and organic geochemical methods to assess the organic matter source input, thermal maturity, paleo-environmental conditions, kerogen type, hydrocarbon quality, and the correlation between this oil and its potential source rock in the basin. The extracted oil samples are characterized by very high contents of saturated hydrocarbons (average 62.76%), low contents of aromatic hydrocarbons (average 16.11%), and moderate amounts of nitrogen–sulfur–oxygen or resin compounds (average 21.57%), suggesting that the fluid petroleum extracted from the Oligocene oil sands is of high quality. However, a variety of biomarker parameters obtained from the hydrocarbon fractions (saturated and aromatic) indicate that the extracted oil was generated from source rocks with a wide range of thermal maturity conditions, ranging from the early to peak oil window stages, which are generally consistent with the biomarker maturity parameters, vitrinite reflectance (approximately 0.6%), and Tmax values of the Middle Jurassic carbonaceous mudstones and organic-rich mudstone source rocks of the Dameigou Formation, as reported in the literature. These findings suggest that the studied oil is derived from Dameigou Formation source rocks. Furthermore, the source- and environment-related biomarker parameters of the studied oil are characterized by relatively high pristane/phytane ratios, the presence of tricyclic terpanes, low abundances of C27 regular steranes, low C27/C29 regular sterane ratios, and very low sterane/hopane ratios. These data suggest that the oil was generated from source rocks containing plankton/land plant matter that was mainly deposited in a lacustrine environment and preserved under sub-oxic to oxic conditions, and the data also indicate a potential relationship between the studied oil and the associated potential source rocks. The distribution of pristane, phytane, tricyclic terpanes, regular steranes and hopane shows an affinity with the studied Oligocene Lower Ganchaigou Formation oil to previously published Dameigou Formation source rocks. In support of this finding, the pyrolysis–gas chromatography results of the analyzed oil asphaltene indicate that the oil was primarily derived from type II organic matter, which is also consistent with the organic matter of the Middle Jurassic source rocks. Thus, the Middle Jurassic carbonaceous mudstones and organic rock mudstones of the Dameigou Formation could be significantly contributing source rocks to the Oligocene Lower Ganchaigou Formation oil sand and other oil reservoirs in the Northern Qaidam Basin.

Phase characteristics and geological significance of coal-generated hydrocarbon: Take the Minhe Basin as an example

The phase characteristics of petroleum fluids are directly related to the hydrocarbon accumulation, and through exploration and development, the evolution process of hydrocarbon generation from coa...

A review on the application of differential scanning calorimetry (DSC) to petroleum products

Differential scanning calorimetry (DSC) can be used to obtain a variety of thermodynamic or kinetic data of petroleum products. The application of DSC to petroleum fluids includes characterization of crude oils, studying bulk and confined space phase behavior of hydrocarbons, and evaluating the glass transition in crude oils. In addition, the kinetic data of the pyrolysis, combustion, and oxidation of crude oils can be obtained using DSC. In this work, a comprehensive review of the application of DSC to petroleum-based products is provided that integrates different approaches in the literature in order to provide a constructive platform for future studies. Also, the limitations of the method are elaborated in detail, and recommendations are provided to appropriately optimize the accuracy and applicability of DSC to study petroleum products. The impact of different operating parameters in using DSC including the thermal scanning rate, pressure, modulating temperature program, and analysis method is systematically discussed. Also, the effect of neglecting thermal radiation in DSC experiments is highlighted to ensure that future studies consider this important phenomenon once analyzing the raw data. As well, the advantage of coupling DSC with other analytical techniques is carefully reviewed to underline that precious information that can be obtained once DSC is integrated with other methods. This comprehensive review expresses that DSC has different themes of applications to the research and development in petroleum industry. Due to its simplicity, precious and rapid data collection features, DSC is one of the primary methods for characterizing petroleum fluids. Yet, further advancements both in the equipment design and in data analysis is urged to improve the applicability of DSC to crude oils and their fractions.

Impacts of Thermochemical Sulfate Reduction, Oil Cracking, and Gas Mixing on the Petroleum Fluid Phase in the Tazhong Area, Tarim Basin, China

Petroleum fluids in the deep Ordovician reservoirs of the Tarim Basin vary in phase and molecular composition. An improved understanding of the secondary geochemical alteration processes is critical for successful exploration and fluid property prediction. Three oil samples from the Ordovician condensate and oil reservoirs were analyzed using comprehensive 2D gas chromatography/time-of-flight mass spectrometry (GC×GC-TOFMS). Molecular signatures revealed varying levels of diamondoids and organosulfur compounds (OSCs) that were preferentially enriched in the condensate and a gas saturated oil; however, these molecular signatures were not generated through in-reservoir oil cracking or thermochemical sulfate reduction (TSR) as favorable thermal and medium conditions were not available. Severe cracking and TSR occurred in deeper Cambrian source-reservoirs and generated secondary geochemical products including diamondoids, OSCs, and H2S. Such secondary products were carried by dry gases derived for oil cracking that migrated upward through the fault system and filled shallower Ordovician oil reservoirs. The differential secondary gas charge can account for the variable fluid composition and varying phase behavior, i.e. the transition from unsaturated oil to gas saturated oil and then to condensate. Condensates were formed from the dissolution of primary oils due to extra gas mixing.

Magnetic treatment of petroleum and its relation with asphaltene aggregation onset (an atomistic investigation)

Magnetic treatment is often used in certain oil industries for alterations in petroleum rheological properties. In this report, we introduce the scientific basis for the role of magnetic treatment on the onset of asphaltenes aggregation from petroleum fluids. Molecular dynamics simulations are used to study the effect of magnetic fields that are applied to three different model asphaltenes (A1-A3) in paraffinic and aromatic oil media. Radial distribution functions, hydrogen bond interactions, and the simulation trajectories are produced and analyzed. Our simulation results show that the onset of asphaltene aggregation in petroleum fluids is affected by the magnetic field and it is a function of its strength. In a paraffinic medium, magnetic field reduced aggregation of the model asphaltenes studied in the range of 20–35%. Where magnetic field of 1.5T caused a high disruption of A1 aggregation and changed the dominated stacking. However, the highest disruption of A2 and A3 asphaltenes was at 1.0T. In an aromatic medium, magnetic field reduced association of the model asphaltenes studied in the range of 25–70%. Where 0.5T diminished the association of A2 and A3 asphaltenes while 1.0T was able to do that for A1 asphaltene. The stacking modes and distances between asphaltene molecules were also affected by magnetic field. For example, in paraffinic medium, 0.5T enhanced the aggregation of A1 and A2 asphaltenes with multiple-layer stacking where some of the peaks appeared farther than the reported cutoff of asphaltene stacking. Hydrogen bond results showed that magnetic fields did changes on the average number of hydrogen bonds. These changes were due to changes in the orientation and the distances between asphaltene molecules. The difference in asphaltene response to the magnetic treatment was due to the differences in their structures. Overall, the effect of magnetic field on the onset of asphaltene aggregation is dependent on the magnetic field strength, asphaltene architecture, and the medium. Results of this simulation are applicable to asphaltene behavior in real crude oil.

A review on casing while drilling technology for oil and gas production with well control model and economical analysis

Abstract The extraction of petroleum fluids from sub-surface accumulations mandates the drilling of a well into the formation containing the accumulation. The drilling techniques have evolved over time to overcome several challenges while some of the issues still prevail with the currently used drilling practices like loss circulation, large tripping time to change bottom hole assembly, stuck pipe problems and low well bore stability, to name a few. These decrease the drilling efficiency and increase the Non-Productive Time (NPT) of this highly capital-intensive industry encouraging the Petroleum Industry to look for new technology. Casing while Drilling (CwD) is a technique of drilling which has been proven to alleviate many of the problems faced while drilling. In this method, drilling and casing of a well bore is carried out simultaneously, which improves the drilling efficiency by reducing the NPT. It has proven to be beneficial in controlling loss circulation and improving wellbore stability by ‘Plastering’ effect, high quality cement job and increased rig floor safety. It uses smaller rig and less fuel thereby reducing carbon footprint in the environment. This paper studies comprehensive well control and casing string design consideration. Economics encourages its application that has been discussed in the paper. A case study on the application of CwD in Malay basin for top hole drilling is presented. Finally, the paper briefly outlines the technical challenges that need attention to get better results from CwD.

A novel educational laboratory experiment for constant-mass expansion of petroleum fluids

This paper presents a new way to conduct an educational experiment for bubble-point determination of a hydrocarbon mixture. The visual fluid cell newly designed for educational purposes made it possible to teach bubble-point determination safely at low cost within a few hours for groups of students in a laboratory class. The educational experiment developed has been successfully implemented for three semesters at the authors’ institution with positive responses from a vast majority of the students. It is hoped that this paper helps other interested instructors enhance students’ learning experience in the subject of fluid properties.

Estimate of Saturation Pressures of Crude Oil by Using Ensemble-Smoother-Assisted Equation of State

The equation of state (EOS) has been extensively used to evaluate the saturation pressures of petroleum fluids. However, the accurate determination of empirical parameters in the EOS is challenging and time-consuming, especially when multiple measurements are involved in the regression process. In this work, an ensemble smoother (ES) -assisted EOS method has been proposed to compute the saturation pressure by intelligently optimizing the to-be-tuned parameters. To be specific, the to-be-tuned parameters for the Peng–Robinson EOS (PR EOS) are integrated into a model input matrix and the measured saturation pressures are collected into a model output matrix. The model input matrix is then integrally and iteratively updated with respect to the model output matrix by using the iterative ES algorithm. For convenience, an in-house module is compiled to implement the ES-assisted EOS for determining the saturation pressures of crude oils. Subsequently, the experimentally measured saturation pressures of 45 mixtur...

Oil spill modeling in deep waters: Estimation of pseudo-component properties for cubic equations of state from distillation data

Deep-water oil spills represent a major, localized threat to marine ecosystems. Multi-purpose computer models have been developed to predict the fate of spilled oil. These models include databases of pseudo-components from distillation cut analysis for hundreds of oils, and have been used for guiding response action, damage assessment, and contingency planning for marine oil spills. However, these models are unable to simulate the details of deep-water, high-pressure chemistry. We present a new procedure to calculate the chemical properties necessary for such simulations that we validate with 614 oils from the ADIOS oil library. The calculated properties agree within 20.4% with average values obtained from data for measured compounds, for 90% of the chemical properties. This enables equation-of-state calculations of dead oil density, viscosity, and interfacial tension. This procedure enables development of comprehensive oil spill models to predict the behavior of petroleum fluids in the deep sea.

Aqueous- and solid-phase molybdenum geochemistry of oil sands fluid petroleum coke deposits, Alberta, Canada

Fluid petroleum coke generated at oil sands operations in the Athabasca Oil Sands Region of northern Alberta, Canada, contains elevated concentrations of molybdenum (Mo) and other metals including nickel (Ni) and vanadium (V). Solid-phase Mo concentrations in fluid petroleum coke are typically 10 to 100 times lower than V and Ni, yet dissolved Mo concentrations in associated pore waters are often comparable with these metals. We collected pore water and solids from fluid petroleum coke deposits in the AOSR to examine geochemical controls on Mo mobility. Dissolved Mo concentrations increased with depth below the water table, reaching maxima of 1.4–2.2 mg L−1, within a mixing zone between slightly acidic and oxic meteoric water and mildly alkaline and anoxic oil sands process-affected water (OSPW). Dissolved Mo concentrations decreased slightly with depth below the mixing zone. X-ray absorption spectroscopy revealed that Mo(VI) and Mo(IV) species were present in coke solids. The Mo(VI) occurred as tetrahedrally coordinated MoO42− adsorbed via inner- and outer-sphere complexation, and was coordinated in an environment similar to Fe-(hydr)oxide surface complexes. The OSPW likely promoted desorption of outer-sphere Mo(VI) complexes, resulting in higher dissolved Mo concentrations in the mixing zone. The principal Mo(IV) species was MoS2, which originated as a catalyst added upstream of the fluid coking process. Although MoS2 is likely stable under anoxic conditions below the mixing zone, oxidative weathering in the presence of meteoric water may promote long-term Mo release.

A Linear Extrapolation of Normalized Cohesive Energy (LENCE) for fast and accurate prediction of the asphaltene onset pressure

Knowledge of the conditions at which asphaltenes precipitate from petroleum fluids is useful in the development of enhanced oil recovery scenarios and field development plans. In this work we present a semi-empirical linear model for approximating onset pressure by means of a Linear Extrapolation of Normalized Cohesive Energy (LENCE). A normalized cohesive energy function is found to correlate linearly with temperature along the asphaltene onset curve for several crude oils from different regions. The linear trend is observed from simulation results using the perturbed-chain version of the Statistical Associating Fluid Theory Equation of State (PC-SAFT EoS). LENCE can be used to approximate the asphaltene onset pressure (AOP) for petroleum fluids at different temperatures from knowledge of two experimental onset pressures. Several case studies are presented to demonstrate the capability of LENCE to accurately predict asphaltene onset pressure as well as detecting experimental uncertainties in reported measurements from near infrared (NIR) and high pressure microscopy (HPM) experiments. LENCE model can reproduce AOP modeling results from PC-SAFT with an average absolute percent deviation of 2.38%, with 5 times faster computational speed. It is found that PC-SAFT predicts a minimum temperature at which an upper asphaltene onset exists. Below this temperature, asphaltenes are inherently unstable in solution as predicted by PC-SAFT. This behavior seems to be a characteristic of SAFT-based models and is not yet supported by experimental evidence. Compared to PC-SAFT, the LENCE model exhibits improved characteristics for the liquid-liquid phase boundary in the low temperature region.