Petroleum Phase Research Articles

Impact of Overpressure on the Preservation of Liquid Petroleum: Evidence from Fluid Inclusions in the Deep Reservoirs of the Tazhong Area, Tarim Basin, Western China

The complexity of petroleum phases in deep formations plays an important role in the evaluation of hydrocarbon resources. Pressure is considered to have a positive impact on the preservation of liquid oils, yet direct evidence for this phenomenon is lacking in the case of deep reservoirs due to late destruction. Here, we present fluid-inclusion assemblages from a deep reservoir in the Tazhong area of the Tarim Basin, northwestern China, which formed as a direct consequence of fluid pressure evolution. Based on thermodynamic measurements and simulations of the coexisting aqueous and petroleum inclusions in these assemblages, the history of petroleum activities was reconstructed. Our results show that all analyzed fluid-inclusion assemblages demonstrated variable pressure conditions in different charging stages, ranging from hydrostatic to overpressure (a pressure coefficient of up to 1.49). Sequential petroleum charging and partial oil cracking may have been the main contributors to overpressure. By comparing the phases of petroleum and fluid pressures in the two wells, ZS1 and ZS5, it can be inferred that overpressure inhibits oil cracking. Thus, overpressure exerts an important influence on the preservation of liquid hydrocarbon under high temperatures. Furthermore, our results reveal that the exploration potential for liquid petroleum is considerable in the deep reservoirs of the Tarim Basin.

Geochemistry and accumulation of the ultra-deep Ordovician oils in the Shunbei oilfield, Tarim Basin: Coupling of reservoir secondary processes and filling events

Ultra-deep (7300 m–8900 m) condensed and volatile oil reservoirs have been discovered in the Ordovician reservoirs of the Shunbei oilfield, in the Tarim Basin. This study describes the petroleum accumulation process in the Shunbei oilfield by combining an analysis of its geochemical characteristics with seismic section observations and an analysis of petroleum filling events. Geochemical techniques are used to determine the sources, maturity, secondary processes, accumulation periods, and timing of petroleum filling. Analysis of fluid inclusion homogenization temperatures and burial-thermal histories indicates distinct petroleum filling events. Specifically, the north sub-section of the No. 5 fault zone experienced two petroleum filling periods during the late Caledonian and Indosinian epochs while the No. 1 fault zones and the mid-south sub-sections of the No. 5 fault zones experienced three distinct filling periods, encompassing the late Caledonian, Indosinian, and Himalayan periods. The CO2 concentrations and δ13CCO2 values suggest the presence of secondary microbial gases, primarily thermogenic gases. Gas component analysis reveals a transition from kerogen degradation gas to oil cracking gas from north to south. The detection of intact n-alkanes and compounds of the 25-norhopanes series in oil samples suggests a mixture of early biodegradable oil with late fresh oil in the area. Seismic sections reveal diabase intrusions with strong axial reflections. Local hydrothermal activities during the Permian era rapidly cracked saturated hydrocarbon biomarkers, forming polycyclic aromatic hydrocarbons in the oil. Hydrothermal activity in the south sub-section of the No. 5 fault zone depleted the hydrocarbon-generating capacity of the underlying source rocks. Petroleum charged during the Indosinian period likely originated from potential petroleum reservoirs in the Cambrian system. This explains the comparatively low temperature of the SHB57X reservoir (163.32 °C) and the lack of strong hydrothermal activity in the late stage, but no biomarkers of the second-stage charged oil have been detected. Biomarker detection and gas genesis in the mid-south sub-section of the No. 5 fault zone and in the No. 1 fault zone suggest weak or no hydrothermal activity, with Cambrian source rocks maintaining their hydrocarbon generation capacity. Gas filling in the Himalayan period caused evaporative fractionation in the original reservoirs, resulting in a disproportionate (2-MH+2,3-DMP)/(3-MH+2,4-DMP), producing high K1 values in the light hydrocarbons in the present petroleum reservoirs. Differences in gas charging events in the Himalayan period led to the present distribution of petroleum phases.

Nature and occurrence, geochemical characteristics, and families of the crude oils in Sirt Basin, Libya: Implication for super rift basin petroleum system

In this study, we investigated the nature and characteristics of petroleum fluids in a super-global basin situated in the central north of Libya. With over 100 discovered fields (comprising oil and gas), this study aimed to understand the basin's petroleum accumulation mechanism (PAM), thereby shedding light on the factors contributing to significant petroleum discoveries in North Africa (Libya). The primary objective of this study was to provide a detailed regional refined oil family distribution and new insights into the total petroleum system (TPS) of the basin. This analysis was based on the integration of regional geology and organic geochemistry. Additionally, we utilized the physical properties of petroleum, such as API and sulphur content (%S), to obtain a better understanding of the regional physical nature of petroleum types and properties. Organic geochemical data for the basin fields were compiled, focusing on key biological marker and carbon isotope (‰ δ13C) data for saturated and aromatic compounds. These data were used to understand the origin, depositional source, and thermal maturity of the generated, migrated, and accumulated petroleum fluids. The study established specific types of organofacies and their relationships with petroleum phase characteristics, including type and quality, categorized into known groups (e.g., B, C, and D/E). Hierarchical cluster analysis (HCA) and map-based presentation approaches were used to determine the spatial types and distributions of oil and gas families in the basin. This was achieved by selecting the input parameters from various datasets and defining the significant parameters to characterize the distribution patterns. The findings indicate that the bulk fluid of the Sirt Basin primarily resembled Brent oil, which was characterized by a very low sulphur content (less than 1.4%). The API gravity ranged from 30 to 65, reflecting a diverse range of oil types within the basin. The crude oils in the basin were primarily derived from marine organofacies, predominantly from type B. This inference is supported by related biomarkers such as regular steranes and isoprenoids. Furthermore, the analysis of carbon isotopes provided a similar indication, with values ranging from −32 to −27 for ‰ δ13C for saturates and −31.2 to −25.4 ‰ δ13C for aromatic compounds. The thermal maturity biomarker ratio (Ts/Ts + Tm) of the Sirt Basin crude oils varied from 0.35 to 0.92, suggesting different levels of thermal maturity, typically ranging from the mid to late mature stages. This observation is consistent with the indication based on the 22S/22S + 22R ratio. The basin exhibited four dominant oil families and eight subfamilies with the same geochemical characteristics (HCA-based analysis), including early and later generations, relatively sulphurized oils, and condensate families.

Simulation of petroleum phase behavior in injection and production process of underground gas storage in a gas reservoir

On the basis of analyzing the fluid phase behavior during the transformation from gas reservoir to gas storage, a mathematical model and an experimental simulation method are established to describe the oil-gas phase behavior during the whole injection- production process of gas storage. The underground gas storage in the Liaohe Shuang 6 gas reservoir with oil rim is taken as a typical example to verify the reliability and accuracy of the mathematical model and reveal characteristics and mechanisms of fluid phase behavior. In the gas injection stage of the gas storage, the phase behavior is characterized by mainly evaporation and extraction and secondarily dissolution and diffusion of gas in the cap to oil in the oil rim of the reservoir; the gas in gas cap increases in light component content, decreases in contents of intermediate and heavy components, and increases in density and viscosity. The oil of the ring decreases in content of heavy components, increases in contents of light and intermediate components, decreases in density and viscosity, and increases in volume factor and solution gas oil ratio. In the stable operation stage of periodic injection-production of gas storage, the phase behavior shows that the evaporation and extraction capacity of injection gas in the cap to oil rim is weakened step by step, the phase behavior gradually changes into dissolution and diffusion. The gas in gas cap decreases in content of intermediate components, increases in content of light components slowly, and becomes lighter; but changes hardly in density and viscosity. The oil in the oil rim increases in content of heavy components, decreases in content of intermediate components, rises in density and viscosity, and drops in volume factor and solution gas oil ratio.

Assessment of the thermal maturation, organofacies, and petroleum generation history of Sirte Shale Formation in Sirt Basin, Libya

The current study is conducted to investigate the upper Cretaceous (Campanian) Sirte shale Formation to better understand the regional abundance of the organofacies, thermal maturation levels, and the petroleum generation and expulsion histories during the geological time in one of the most important petroliferous basins in North Africa (Sirt Basin). Rock-Eval pyrolysis analysis of 988 samples in 56 wells that penetrated the Cretaceous section in the Sirt Basin was used to screen and study the geological and geochemical characteristics of the Sirte shale Formation. Multi-dimensional basin modeling, including 1D burial histories and 2D modeling approaches, was calibrated with %VRo and pyrolysis Tmax data to establish refined regional maturity of the Sirte shale Formation. By using the Rock-Eval data, the type, occurrence, and distribution of organofacies in time and space were investigated using analytical assessment procedures and present-day mapping, such as total organic carbon (%TOCp), hydrogen index (HIp), and kerogen transformation ratio (TRp) to define the lateral and vertical special variation. Key biological marker (biomarkers) data is used to determine their special types, abundance, and host sedimentary environments. We used integrated geochemistry with basin modeling to define the Sirte shale petroleum generation and expulsion history, petroleum phase-type and quantity, and expulsion efficiency. Results indicate that the current maturation levels in the general range of 0.4–1.35 %VRo (equivalent to 405 °C–460 °C pyrolysis Tmax) that found to allow Sirte shale Formation to enter transformation levels ranging from 20% to 91%, which is equivalent to 1,615 m–3,627 m burial depth. Sirte shale Formation is dominated by two types of organofacies (B and D/E), which are characterized by %TOC up to 5% and hydrogen index from 400 to 700 mg HC/g TOC with sudden lateral and vertical variation due to the influence of the marine and transitional – terrestrial sedimentary environments. Similar indications from the biomarker data were Pr/Py ratio shows a significant existence of anoxic and dysoxic environments (generally, 0.4–2.4). Alga marine (dominant), mixed, and minor terrestrial organic matter was defined to dominate the Sirte shale Formation as indicated by Pr/nc-17 and Py-nc18 data. The petroleum generation history of the Sirte shale Formation occurred in the Oligocene time (∼30 Ma). The higher expulsion efficiency for the oil phase, up to 84% detected in the deeper parts of the basin, and lower gas expulsion efficiency with its maximum up to 63%. During the geological time, two primary petroleum phases were generated and expelled (oil and gas) from the Sirte shale. The bulk fluid properties generated from Sirte Shale Formation indicate that range of GOR from 400 to 2000 scf/bbl and API in the range of 30–60.

Petroleum phase evolution at high temperature: A combined study of oil cracking experiment and deep oil in Dongying Depression, eastern China

Numerous light oil reservoirs have been discovered in the lower part of Mbr 4 of Paleogene Shahejie Fm in the Dongying Depression, Bohai Bay Basin, eastern China. The petroleum phases and reservoir-forming models are crucial to understanding the hydrocarbon accumulation mechanisms in the deep lacustrine layers. The deep formation temperature and pressure, the PVT phase diagrams, as well as the burial-thermal history were simulated and restored based on the results of oil cracking experiments and the analysis of measured data of geological sections in the Dongying Depression. The process and laws of hydrocarbon accumulation were summarized. The cricondentherm envelopes depict a series of variations when the molar percentages of CO2, CH4, C2-5, and C6+ in the fluid composition change. In the process of oil cracking, the cricondenbar increases with the increase in the molar percentage of CH4. With the increase in molar percentage of C2-5 and C6+, the cricondenbar decreases continuously. According to simulations of fluid composition and phase state, the oil reservoirs in this area are primarily oil-rim condensate gas reservoirs and volatile oil reservoirs. Based on burial-thermal history recovered under the constraint of measured vitrinite reflectance (VRo), the homogenization temperature of fluid inclusions suggests two main periods of petroleum charging: in the late deposition of the Mbr 3 of the Paleogene Shahejie Fm and Guantao Fm in the Eocene. In the second charged stage, the oil cracking gas from deep places in the depression was injected into the primary oil and gas reservoirs, causing the changes and differentiation of fluid phases in the reservoirs. The gas invasion and evaporative fractionation caused by late natural gas filling are key factors for the formation of light oil reservoirs.

Phase fractionation and oil mixing as contributors to complex petroleum phase in deep strata: A case study from LG7 block in the Tarim Basin, China

Integrated geochemical analysis was conducted on oil and gas samples from the LG7 block, Tarim Basin, China, to investigate the causal mechanisms for the complex petroleum phase. Consistency in biomarker derived parameters suggest that heavy oil, black oil, and condensate, though vary in physical properties and phase state, share a genetic affinity and are all mature oil generated at peak oil window. However, mass loss and double-peaks pattern in n-paraffins of black oil and heavy oil, and much higher maturity of gas and some oil fractions (diamondoids) jointly suggest the oil samples in the study site have suffered secondary alteration process including phase fractionation and mixing. In combination with tectonic evolution analysis, the study site experienced severe uplift after primary oil accumulation and thus formed biodegraded heavy oil in local highs. Since Neogene, the introduction of oil-cracking gas from deeper strata charged early oil accumulations and caused phase fractionation, during which primary oil was fractionated into vaporized light oil and heavy oil residue. Vaporized light oil continued to migrate towards higher positions and were readily to either mix with other oil residue and heavy oil, or to be trapped to form secondary condensate in favorable reservoirs. Thus, the complex disordered distribution of heavy oil, black oil, and condensate is observed within a relatively small area. Our reconstruction of the petroleum accumulation and alteration process speculates future exploration endeavors to potential oil-cracking gas/condensate accumulations in the study area.

Formation processes of gas condensate reservoirs in the Baiyun Depression: Insights from geochemical analyses and basin modeling

The petroleum phase in a petroleum reservoir and the formation process of gas condensate reservoirs became a hotspot in petroleum geoscience. This study recovered the petroleum migration processes in the western sag of the Baiyun Depression based on the geochemical analyses and basin modeling to illustrate the formation processes of gas condensate reservoirs in the Baiyun Depression. The geochemical parameters of light oil and natural gases indicated that they originated from the Enping Formation. Basin modeling indicated that the Enping source rocks in the western sag were mature after 13.8 Ma. The petroleum migrations in the Enping and Zhuhai Formations were vertical, and the lateral migration occurred in the Lower Zhujiang Member. The petroleum generation–migration and temperature–pressure conditions mostly controlled the petroleum phase. The Enping source rocks produced some amount of oil in the oil window and generated considerable amount of gas later. Continuous gas charging increased the gas–oil ratio, and the light oil dissolved in the gas. With the increase in temperature and pressure, the oil reservoir eventually turned into a gas condensate reservoir. The gas condensate reservoir formation was mainly related to petroleum generation–migration–accumulation processes in the western sag. This study could contribute to petroleum exploration and development in the Baiyun Depression and some similar basins.

INVESTIGATION OF EFFECT OF NEW REAGENT COMPOSITIONS ON VARIOUS CRUDE OIL EMULSIONS OF AZERBAIJAN

The article is devoted to the decomposition of strong water-crude oil emulsions formed during the preparation of crude oil for transportation. In the petroleum industry, there is a great need to develop new chemicals to improve the degradation efficiency of stable water- crude oil emulsions. Decomposition of strong water-oil emulsions is considered a key part of crude oil preparation for transportation. Therefore, the development of new demulsifying compositions to improve the degradation efficiency of stable crue oil emulsions remains relevant. This paper presents the results of studies of dehydration processes of Azerbaijani oils and emulsions depending on the degree of watering. The composition is based on Disulfan 4411, Disulfan 13280, Sarola 412, Difron 9426, ND-12 and Gossipol, they were also used to prepare Azerbaijani oil for transportation during laboratory tests of demulsification efficiency (except Difron 9426). During laboratory tests, it was determined that the best results on the degree of residual dehydration of petroleum phases were achieved using a composition called KAV-22. Keywords: Muradhanly, Bulla, Balakhany, Neft dashlari, Dehydration, Surahany, KAV-22.

Formation and distribution of ethanodiamondoids in deeply buried marine oil from the Tarim Basin, China

Diamondoids are often enriched in highly mature oil due to their high resistance to thermal stress. Ethanodiamondoids have similarly high thermal stability. We have detected ethanodiamondoids from 75 oil samples from deep marine carbonate strata in the Tarim Basin, China. Based on thermal simulation experiments on source rock and oil samples, we propose that ethanodiamondoids are gradually created with increasing thermal evolution and oil cracking. Their formation is likely due to free radical reactions of diamondoids with ethane or ethene formed from the cracking of alkanes. A proxy is proposed for the rapid determination of the degree of oil cracking and the petroleum phase based on the relationship between types and concentrations of ethanodiamondoids and diamondoids.

Origins and deep petroleum dynamic accumulation in the southwest part of the Bozhong depression, Bohai Bay Basin: Insights from geochemical and geological evidences

Latest exploration practices revealed appreciable petroleum resources in the deep pre-Cenozoic reservoirs in the southwest area of the Bozhong depression; however, the origins and accumulation mechanisms of deep hydrocarbons remain not fully understood. Here, an integrated study of the geochemical characteristics of overlying source rocks, maturity evaluation of petroleum, and origin of natural gas was conducted to characterize the dynamic petroleum accumulation and illustrate the main factors influencing the differential phases of petroleum distribution in the research area. The third member of the Dongying Formation (Ed3) mudstone in the research area displays high organic richness and is characterized by oil-prone organic matter, indicating high petroleum potential. The oils contained in the CFD18 and BZ13 buried-hill traps were mainly derived from the Ed3 and Shahejie Formation (Es) source rocks, respectively, with natural gas of kerogen cracking origin. Buried-hill oil from the BZ13 field displays a high thermal maturity than that of the CFD18 oils, which was evidenced by maturity parameters of saturated and aromatic hydrocarbons and concentrations of stigmastane. Nevertheless, maturity index of diamondoids and carbon isotopic composition of natural gas indicate the possible presence of mixing of higher mature Es fluids for the CFD18 field. This research underlines the contribution of the overlapped effective source rocks to the buried-hill traps. The causes of multiple petroleum phases in the deep reservoirs in the research area are mainly linked to dynamic petroleum accumulation rather than source rock type and oil secondary cracking. Although faults are present to act as vertical migration conduits due to late-stage activation with high intensity, abundant petroleum supply due to near-source charge and favorable constitution relationship of source rock and reservoir rock provide crucial conditions for deep petroleum accumulation in a tectonic activation zone.

Reviewing Cyclonic Low-Shear Choke and Control Valve Field Experiences

Summary In hydrocarbon production and processing, choke and control valves mix and emulsify petroleum phases. The consequence is often that the efficiency of separation processes is affected and finally that the quality of oil and water phases is degraded. Over the last few years, low-shear valves targeting petroleum processes have emerged on the market. This paper presents four separate live-fluid experiences from low-shear valve installations, each surveyed and documented by an independent third party. Three of the installations refer to choke valves, whereas the fourth installation refers to a control valve. For each installation, standard choke and control valves were used as reference valves. In terms of downstream separation efficiency, the low-shear choke valves reduced oil-in-water concentrations respectively by 70, 45, and 60%, by total average. In the control valve application, the low-shear valve, which was located between the hydrocyclones and a compact flotation unit, reduced the oil-in-water concentration by 23%. In sum, the field installations have demonstrated that low-shear valves significantly and consistently reduce oil-in-water concentrations and thus improve the produced water quality. The results signify that low-shear valves may be used in debottlenecking separation and produced water treatment processes, reducing the environmental influence from produced water discharges. Because the low-shear technology enables processing of petroleum phases with less effort, energy, and chemicals, it also reduces emissions to air.

Virtual Special Issue of the 21st International Conference on Petroleum Phase Behavior and Fouling (PetroPhase2020)

Virtual Special Issue of the 21st International Conference on Petroleum Phase Behavior and Fouling (PetroPhase2020)

Timing and origin of multiple petroleum charges in the Solveig oil field, Norwegian North Sea: A rhenium-osmium isotopic study

The Re-Os geochronometer constrains the timing of petroleum formation and provides an oil-source isotopic correlation tool for improved geologic knowledge and exploration success. However, the effects of secondary processes that may sometimes complicate interpretations are not well understood. This paper discusses Re-Os systematics in a petroleum system that experienced extensive asphaltene precipitation upon mixing of different oil phases. The Solveig oil field (formerly Luno II), Utsira high, Norwegian North Sea, comprises three structural compartments that capture different stages of the mixing process. In the central compartment, an Re-Os age of circa 40 Ma for whole-rock extracts sampling the residual (asphaltene-rich and biodegraded) oil below the oil–water contact is consistent with burial models for Paleocene–Miocene generation. A 10-m-thick, asphaltene-rich (65 wt. %) tar mat zone precipitated upon mixing of at least two components does not yield meaningful ages. The Re-Os isochrons for the free-flowing crude oil and whole-rock extracts from the oil leg above the tar mat zone indicate circa 10 to 0 Ma ages for the younger oil phase, supporting independent estimates for recent oil influx. Decreasing 187Os/188Os from maltenes to asphaltenes in oil from the southeastern compartment are highly unusual and provide geochemical evidence for recent mixing, consistent with the strong asphaltene-in-oil gradient. Very low and remarkably uniform Re/Os ratios for all petroleum phases, combined with relatively low and uniform 187Os/188Os ratios, strongly support isotopic overprint of the Re-Os system, likely during water–oil interaction. Despite this overprint, Re-Os ages retain information on primary events, whereas initial 187Os/188Os ratios are strongly affected.

Peculiarities of Dispersion of Oil Raw Materials into Aqueous Solutions of Polycomplexones Surfactants

A study was carried out on the dispersion of heavy petroleum feedstock in aqueous solutions of polycomplexon surfactants derived from triglycerides and mucopolysaccharides with and without sodium hydroxide. Up to 97.5% of the sulfur-containing compounds and up to 86% if the vanadium and nickel compounds enter the aqueous phase along with the mucopolysaccharide derivatives upon phase separation depending on the contents of surfactant and sodium hydroxide. A portion of the triglyceride derivatives remains in the petroleum phase.

Integration of Solvent Extraction and Noncatalytic Esterification for the Treatment of Acidic Feedstocks

The possibility of directly feeding the extract of a liquid-liquid extraction unit to a chemical reactor is analyzed. An example of extraction and non-catalytic esterification of naphthenic acids from acid petroleum crudes is used. Methanol is used both as a solvent and reactant. Separated tests of extraction and reaction are made and the performance of an integrated process is deduced by computer simulation. Thermodynamic and kinetic parameters for extraction of naphthenic acids from an acid crude were determined. A partition coefficient of m=0.66 at 60 °C between the alcoholic and petroleum phases was found. Three succesive batch extractions with a 1:1 vol:vol ratio reduced the acidity from 4.3 to about 1.1 mgKOH/g. Naphthenic acid concentrates were reacted with supercritical methanol in a batch reactor at high temperatures (280 °C) yielding naphthenic esters. 1-2 h of reaction with methanol-to-oil molar ratios of 3-6 yielded 92-96% conversion because of a relatively low value of the equilibrium constan...

19th International Conference on Petroleum Phase Behavior and Fouling

19th International Conference on Petroleum Phase Behavior and Fouling

Multiple linear regression approach for the vitrinite reflectance estimation from well logs: A case study in Sargelu and Naokelekan Formations – Shaikhan-2 Well, Shaikhan oil field, Iraq

The sonic and resistivity logs for Sargelu and Naokelekan Formations in well Shaikhan-2 are utilized to predict vitrinite reflectance values. The precise prediction of vitrinite reflectance can be done based on well logs by applying multiple linear regressions method. This method is an extension from the regression analysis, which incorporates independent values to predict a dependent value. It is expected that both sonic and resistivity log readings in source rock that has reached oil window and hydrocarbons are cooked out of that, to be higher than source rock that is still in diagenesis stage and has not produced any oil and gas. Possible mechanisms to explain decreasing resistivity with increasing maturity include the existence of a conductive petroleum phase (pyrobitumen) and the increase in residual water salinity driven by water vapor solubility in the produced gas. The best matching between the vitrinite reflectance measured from the cutting samples and the vitrinite reflectance predicted from the log data in the well Shaikhan-2 has achieved.

18th International Conference on Petroleum Phase Behavior and Fouling

It is an honor and a pleasure to introduce this special section of Energy & Fuels dedicated to research presented during the 18th International Conference on Petroleum Phase Behavior and Fouling (PetroPhase 2017) that took place in the city of Le Havre, France, when she was celebrating her 500th birthday.

17th International Conference on Petroleum Phase Behavior and Fouling

17th International Conference on Petroleum Phase Behavior and Fouling