Low Sulfur Crude Oil Research Articles

The occurrence and geochemical origin of 9-alkyl HDBTs substituted by long isoprenoid alkyl chains in crude oil

1,1,4a,6-tetramethyl-9-alkyl-1,2,3,4,4a,9b-hexahydrodibenzo[b,d]thiophene (9-alkyl HDBT) was initially found in highly desulfurized diesel oils. This and related organic sulfur compounds (OSCs) have a special shielding structure that make them extremely resistant to hydrodesulfurization. The structure of 9-alkyl HDBTs is likely directly inherited from biological precursors related to terpenoids, but their origins have not been determined. In this study, OSCs were isolated from a low sulfur crude oil from the Junggar Basin in China by the methylation/demethylation method and characterized by gas chromatography-mass spectrometry. A series of 9-alkyl HDBTs substituted with long isoprenoid alkyl chains were identified in the OSCs. Raney nickel desulfurization was conducted to assist the structural identification. The presence of 9-alkyl HDBTs with a β-carotene carbon skeleton and the predominance in specific carbon numbers of alkyl-substituted 9-alkyl HDBTs support a carotenoid origin of such OSCs. Possible geochemical pathways are proposed for the formation of these OSCs via β-carotene, involving processes such as sulfur incorporation, cyclization, aromatization, hydrogenation, and cleavage.

Isolation and characterization of sulfur compounds in a lacustrine crude oil

A high-sulfur (4.69 wt%) crude oil was discovered in the China Bohai Bay Basin which is known to contain low sulfur crude oil. The composition of this high sulfur crude oil and its geological origin are unknown. In this study, thiophenic and sulfidic sulfur compounds were isolated from the crude oil by methylation/demethylation and characterized using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) and gas chromatography-mass spectrometry (GC–MS). Relatively high abundance of sulfur compounds with 30 carbon atoms and 5–7 double bond equivalence (DBE), which were assigned to sulfurated steranes with thiophene or tetrahydrothiophene moieties. Some of these compounds have not been reported in fossil fuels. In addition to commonly found sulfur compounds in petroleum feedstock, such as benzothiophenes and dibenzothiophenes, other structural sulfur compound types were detected: long-chain 2,5-di-n-alkylthiolanes, 2,5-di-n-alkylthianes, bicyclic terpenoid sulfides, isoprenoid thiophenes, and isoprenoid benzothiophenes. The presence of abundant biomarker sulfur compounds suggests that the sulfuration of the high sulfur crude oil was occurred in the early diagenesis stage instead of a thermochemical sulphate reduction (TSR) process.

Quantitative and Qualitative Analysis of Three Classes of Sulfur Compounds in Crude Oil.

Owing to the environmental hazards arising from sulfur-containing combustion products, strong legal regulations exist to reduce the sulfur content of transportation fuels down to a few ppm. With the ongoing depletion of low-sulfur crude oil reservoirs, increased technological efforts are needed for crude oil refining to meet these requirements. The desulfurization step is a critical part of the refining process but partly suffers from the recalcitrance of certain species to sulfur removal and the inability to quantitatively understand the behavior of individual compound classes during the process. We herein present a new and simple approach for the parallel quantification of three different classes of sulfur species present in crude oils by LC separation and on-line detection and quantification by ICP-MS/MS. This approach will help to estimate the amount of recalcitrant species and thus facilitate the optimization of desulfurization conditions during fuel production.

Computational Chemistry Analysis of Hydrodesulfurization Reactions Catalyzed by Molybdenum Disulfide Nanoparticles

Molybdenum disulfide, MoS2, is a very versatile material used in several applications of science and engineering. In particular, when supported on alumina, it is a widely used catalyst for hydrotreating processes in petroleum refineries. Stringent environmental norms and uncertainty in import of low sulfur crude oil put pressure on refiners worldwide to develop more efficient catalysts to meet the demand of clean fuel. The hydrodesulfurization of thiophene and dibenzothiophene on both unpromoted and nickel-promoted MoS2 catalyst is analyzed using a multiscale approach including classical molecular dynamics (MD) and density functional theory (DFT). MD simulations are performed on a hydrocarbon mixture containing sulfur compounds to determine relative positions of thiophene and dibenzothiophene molecules with respect to the MoS2 catalytic surface previous to possible reactions that are then studied with DFT. The sample box contains a total of 57 515 atoms and is able to represent a realistic size of the nanocatalyst process. Under typical hydrodesulfurization conditions, vacancies are needed for adsorption of sulfur compounds and therefore activation of hydrogen becomes an important step. In addition, complexes of MoS2 with graphene and boron nitride, BN, surfaces are also analyzed. MoS2–graphene complexes show improvement in the efficiency of adsorption of thiophene on the catalyst edge. Both hydrogenation and direct desulfurization pathways are presented on pristine MoS2 clusters as well as under typical hydrodesulfurization conditions.

Characterization of heavy petroleum fraction by positive-ion electrospray ionization FT-ICR mass spectrometry and collision induced dissociation: Bond dissociation behavior and aromatic ring architecture of basic nitrogen compounds

This paper examined the bond dissociation behavior and aromatic ring architecture of basic nitrogen compounds in Sudan heavy petroleum fraction. Both broadband and quadrupole isolation modes positive-ion electrospray ionization (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) coupled with collision induced dissociation (CID) techniques were used to characterize a low sulfur crude oil derived vacuum residuum (VR). The appropriate CID operating condition was selected by comparing the molecular weight distributions of the basic nitrogen compounds under various CID operating conditions. Both odd- and even-electron fragment ions were observed from the mass spectrum, indicating that the heterolytic and homolytic bond cleavages occurred simultaneously during the CID process. The odd-electron fragment ions were predominant in each class species, indicating preferential heterolytic bond cleavages. At the optimal CID condition, the alkyl groups decomposed deeply and just left the aromatic cores of the nitrogen compounds. No significant variation in double bond equivalent (DBE) value was observed between the fragment and parent ions, revealing that the domination of single core structure.

A coulometric method for determining substances that interfere with the measurement of water in oils and other chemicals by the Karl Fischer method.

In order to fulfill a need to measure water in crude oils containing materials that interfere with the measurement of water by the Karl Fischer method, by reacting with iodine or iodide, a coulometric method has been developed and validated using 0.1 mol L(-1) Sodium thiosulfate as a calibrant. These interfering substances were measured in water-mass-equivalents, which were expressed as the mass of water that reacts with an equal mass of iodine in the Karl Fischer method. The SO(2)-free reagent that has been modified reacts quantitatively with sodium thiosulfate, cysteine and ascorbic acid but does not react with vinyl acetate. The level of interfering substances was measured in five transformer oils (including Reference Materials RM 8506 and RM 8507), a high and a low sulfur crude oil (Standard Reference Materials SRM 2721 and SRM 2722 respectively), a white oil, a high-vacuum oil and a high-viscosity base-stock oil. One oil contained less than 10 mg kg(-1) (water-mass-equivalents of interfering substances in oil) and two oils (RM 8507 and Drakeol 35) contained no measurable amount of interfering material (<0.2 mg kg(-1)). SRM 2271, a sour crude oil contained 834 mg kg(-1) (standard deviation (SD)=25 mg kg(-1)) (water-mass-equivalents of interfering substances in oil). Approximately 20% of this material was volatile and an additional 20% appeared to undergo some degradation (possibly oxidation) once the oil was exposed to air. These results indicate that this is a general method for measuring substances in oils that react with iodine and that it is capable of measuring in a variety of oils, using commercial instrumentation, interfering substances that inflate water measurements.

Geochemistry, Palynology, and Regional Geology of Worldclass Upper Devonian Source Rocks in the Madre de Dios Basin, Bolivia: ABSTRACT

Recent exploration drilling indicates the existence of world-class source rock in the Madre de Dios basin, Bolivia. In the Pando-1 X and -2X wells, over 200 m of poorly bioturbated, organic-rich (TOC = 3-16 wt.%) prodelta to shelf mudstones in the Frasnian-Famennian Tomachi Formation contain oil-prone organic matter (hydrogen index = 400-600 mg HC/g TOC). Our calculated source prolificity indices for this interval in these wells (SPI = 15-18 tons of hydrocarbons per square meter of source rock) exceed that for the Upper Jurassic in Central Saudi Arabia. The Tomachi interval is lithologically equivalent to the Colpacucho Formation in the northern Altiplano, the Iquiri Formation in the Cordillera Oriental, and is coeval with other excellent source rocks in North America, Africa, and Eurasia. All of these rocks were deposited under conditions favorable for accumulation of organic matter, including a global highstand and high productivity. However, the Madre de Dios basin was situated at high latitude during the Late Devonian and some of the deposits are interpreted to be of glacial origin, indicating conditions not generally associated with organic-rich deposition. A biomarker and palynological study of Upper Devonian rocks in the Pando-1X well suggests deposition under conditions similar to certain modernmore » fjords. High productivity resulted in preservation of abundant organic matter in the bottom sediments despite a cold, toxic water column. Low-sulfur crude oil produced from the Pando-1X well is geochemically similar to, but more mature than, extracts from associated organic-rich Tomachi samples, and was generated from deeper equivalents of these rocks.« less

Cloud droplet nucleation by crude oil smoke and coagulated crude oil/wood smoke particles

Cloud condensation nuclei (CCN) measurements are reported, taken on smoke aerosol particle samples generated from the combustion of small quantities of high- and low-sulfur crude oils. The smoke samples were stored in 6 m 3 aging bags, and were analyzed over aging times of more than 50 h. Up to 58% of the high-sulfur crude oil smoke particles were found to be active as CCN at water supersaturation of 1% or less, while 20% were active in the low-sulfur case. Ion chromatography data show the presence of small quantities of inorganic and organic compounds which may be the cause of the CCN activity. The low-sulfur crude oil smoke particles were mixed with wood smoke particles, to see if the resulting aggregates are active as CCN.

Statfjord Field: Development Strategy and Reservoir Management

Summary This paper reviews reservoir performance and management of the Statfjord field after 8 years of production. The reasons behind the reservoir development strategies and field experiences are presented. The field comprises three reservoirs produced simultaneously with designated wells for each reservoir: the Upper and Lower Brent and the Statfjord. The two Brent reservoirs are produced with a waterflood, while the Statfjord reservoir is produced with a high-pressure miscible gasflood. The original development plans have been refined on the basis of field performance through an extensive monitoring program and use of reservoir simulation. The induced gamma ray spectra (IGRS) log is used to monitor water movement in the Brent reservoirs, while the compensated neutron tool (CNT) is the main tool used to monitor the gasflood in the Statfjord reservoir. The acquired data have improved the geologic model and the knowledge of fluid movements in all three reservoirs. This resulted in a large and complex reservoir simulation model with more than 20,000 gridblocks. Introduction The Statfjord field, the largest producing oil field in Europe, is located in the prolific northern part of the Viking graben, 125 miles [200 km] northwest of Bergen, Norway, on the U.K./Norwegian boundary (Fig. 1). The field was discovered in March 1974 with the drilling of Well 33/12-1 and was delineated with drilling of 11 additional wells. The field lies mainly in Norwegian Blocks 33/12 and 33/9, but also extends into U.K. Blocks 211/24 and 211/25. The field was unitized in 1976 with Mobil as operator. The equity redetermination of 1979 resulted in 84.1 % of the field being in the Norwegian sector and 15.9 % in the U. K. sector. The operatorship was transferred from Mobil to Statoil in Jan. 1987. The Statfjord field, which is 15 miles [24 km] long and averages 2.5 miles [4 km] in width, is located in a westerly tilted and eroded Jurassic fault block. The main recoverable reserves, about 75 %, are located in the Middle Jurassic Brent group, while the remaining 25 % is in the Lower Jurassic/Upper Triassic Statfjord formation. Both Brent and Statfjord have exceptionally good reservoir characteristics. The estimated ultimate recovery is around 3 × 109 bbl [475 × 106 M3] of oil and 3 × 10 12 Scf [85 × 109 std M3] of gas. Both Brent and Statfjord reservoirs contain highly undersaturated low-sulfur crude oil. Reservoir data and fluid properties are given in Tables 1 and 2. The Statfjord field is being developed with three gravity-based Condeep-type platforms and single-point mooring for offshore oil tanker loading. Production from Platform A commenced in Nov. 1979, while Platform B came on production in Nov. 1982 and Platform C in June 1985. Regular gas sales by pipeline to the U.K. and the European continent began in Oct. 1985. Eighty-nine development wells have been drilled to date to achieve the current average daily oil-production and water-injection rates of 750,000 STB/D [119 000 stock-tank M3 /d] and 1,050,000 B/D [ 167 000 M 3 /d], respectively. As of Dec. 1987, nearly 1.2 × 109 bbl [190 × 10(6) M3] Of oil. or about 40% of the recoverable reserves, has been produced.

Economic Analysis of the North Sea Oil and Gas Region

Summary This study looks into the economics of 27 North Seaoil and gas fields in the U.K. and Norwegian sectorson the basis of the most recent cost and investmentestimates together with the expected productionprofiles. A sensitivity study of each project ispresented, including an economic analysis of therecent changes in the fiscal regime in both sectorsduring 1979-80 as well as a cost study consideringgeneral up-to-date statistics, the recent developmentsconcerning cost escalations, and some costcorrelations. Finally, the North Sea reserves andsupply potentials are discussed. Introduction The North Sea province, containing light, low-sulfurcrude oil as well as gas, and situated in a politicallystable region close to main consumer markets, is oneof the most important petroleum regions in the worldtoday. Since the onshore natural gas discovery inGroningen in 1959, the oil industry's interest in thispart of the world has increased rapidly. The firstoffshore drilling took place in Dutch waters in 1961, while the first application for permission to explorefor oil and gas in Norwegian and U.K. waters was received in 1962. In 1965, the first hydrocarbon wasfound in U.K. waters with a gas discovery, and in1969 the first major oil field was struck in theNorwegian part of the Continental Shelf. Duringthe last 10 years there has been a tremendousdevelopment in the North Sea area, and the region has become one of the most important offshorelaboratories in the world. We investigate the overall economic conditions of27 oil and gas fields in the North Sea sectors of theU.K. and Norway (Fig. 1). These fields have totalproved reserves of approximately 20 Bbbl of oilequivalent. The recoverable reserves for the differentfields vary from the small 50-MMbbl fields (Argylland Auk) to the giant Ekofisk area with a total of3,800 MMbbl of oil equivalent. The productionregimes of the fields in this study are presented inTable 1. Development began on all fields during the1970's--six fields have been completely developedand the other 21 fields are expected to be completedduring the 1980s. The development periods for theNorth Sea fields are between 5 and 14 years.Seventeen of these fields produced oil in 1980, whilethe rest will start production during the next 4 years. Production from these fields is expected to endbetween the mid- 1990's and the end of the firstdecade of the next century. The productive life spanvaries from approximately 10 to 35 years, with thebulk between 10 and 20 years. The average production-to-reserve ratio variesbetween 3 and 14% and the water depths range from45 to 186 m. The Ekofisk area, Brent, and Valhall areevaluated with production of oil as well as gas. TheEkofisk area comprises these fields: Albuskjell, Cod, Edda, Ekofisk, West Ekofisk, Eldfisk, and Tor. TheFrigg field is a gas field, and only the Norwegian part(60.82%)is included in this study. Further, only theNorwegian part of Statfjord(84.09%) and the U.K.part of Murchison (83.75%) are considered. The total development expenditure for the 27 fieldsin our study is estimated to be 56 billion 1980 dollars, while the investment per barrel per day of peakproduction varies from approximately $5,000 to $20,000. JPT P. 2515^