sterane

Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.

Crude oils and rock samples from Cenomanian carbonate oil field (Field A) in the offshore Abu Dhabi were investigated in order to define oil families, paleoenvironment, origin of organic materials and thermal maturity because the origin of crude oils and their thermal history in this field has not been understood well. Especially, maturity profile in this area has not been determined yet because the source rocks don't contain enough amount of vitrinite due to the dominance of marine organic matters. Field A has two culminations above OWC: North structure and South structure. Therefore, we investigated oils from both structures to figure out the geochemical features of each culmination. The Cenomanian carbonate rocks of Field A are composed of shallow marine porous limestone (reservoir rocks) and deep marine lime mudstone (seal rocks and source rocks). Saturated biomarkers (n-alkanes, isoprenoids, steranes and triterpanes) of crude oils from shallow marine porous limestone and core samples from deep marine lime mudstone were determined using gas chromatography-mass spectrometry (GC/MS), gas chromatography-mass spectrometry-mass spectrometry (GC/MS/MS) and gas chromatography-combustion-isotope ratio mass spectrometry (GC/C/IRMS). Ternary diagrams of C₂₇-C₂₉ steranes of all oil samples and core samples show significant similarity among crude oils and source rocks in Cenomanian age. High amount of C₃₀ sterane and the ratio of C₂₇-C₂₉ steranes suggest that the crude oils were generated from Cenomanian marine source rocks. Biomarker maturity parameters such as Ts to Tm ratio and diasterane (Dia) to regular sterane ratio (Reg) were slightly different among the crude oils. The crude oils from South structure were slightly more maturated than those from North structure. The stable carbon isotopic values of individual n-alkanes in the crude oil would be classified into two crude oil families: dominance of lighter carbon in North structure and relatively heavier carbon in South structure. These results were consistent with the results of biomarker maturity parameters such as Ts/(Ts + Tm) and Dia/(Dia + Reg). Thus it was confirmed that the crude oils of North structure and South structure were from same Cenomanian source rock, however, thermal maturity of the crude oils were slightly different between North structure and South structure.

Identification of hydrocarbon generating source rocks and evaluation of their potential are essential in the exploration and development of hydrocarbon resources. For an offshore oil field in Abu Dhabi, we conducted geochemical study using crude oil and core samples from Upper Cretaceous Cenomanian carbonate rocks. The study objectives are 1) correlation of crude oil and source rock with biomarker, and 2) evaluation of the source rock potential.

The Cenomanian carbonate rocks of the oil field are composed of shallow marine porous limestone and deep marine lime mudstone. This Cenomanian lime mudstone was believed as source rock of the crude oil in the interfingered Cenomanian porous limestone reservoirs. However, the origin of crude oil has been poorly constrained with geochemistry yet. In this study, we carried out geological description and RockEval pyrolysis analysis of core samples to evaluate source rock potential of the lime mudstone. Then, biomarkers such as hopane, sterane and compound specific isotopic ratio of n-alkane were analyzed to correlate the source rock and the crude oil samples with GC/MS, GC/MS/MS and GC/C/IRMS for high resolution biomarker measurements and robust interpretation.

As a result, the biomarker fingerprints of the crude oil in porous limestone and the organic material in the lime mudstone show significant similarity. It proves that the crude oil in the porous limestone is migrated from interfingered organic rich Cenomanian lime mudstone. In addition, the lime mudstone shows excellent source rock property (Total Organic Carbon exceeding 4%, Hydrogen Index > 600mg/g TOC) and categorized as Type I/II source rock deposited in marine environment. Furthermore, the biomarkers effectively constrain the maturity of source rock which is difficult to evaluate with Vitrinite Reflectance and RockEVAL analysis. Consequently, the timing of hydrocarbon generation and the area of effective source rock will be interpreted based on our study result with higher confidence.

This study deepens understanding of Cenomanian petroleum system in offshore Abu Dhabi. The result suggests the advantage of biomarker application not only in oil-source correlation but also in source rock maturity analysis.

This paper documents the findings based on interpretation of the geochemical composition of oils from the Bualuang Field located in the western Gulf of Thailand, and how these oils compare with other oils and potential source rocks in the region. The Bualuang Field is located in Block B8/38, on the eastern flank of one of a series of north-south trending, Tertiary half-grabens which are part of the greater Western Basin.

Eight oil samples from five wells on the Bualuang Field were analysed using gas chromatography (GC), gas chromatography-mass spectroscopy (GC-MS) and carbon isotopic techniques. Selected samples were further analysed by GC-MS-MS. This paper provides a review of these analyses, presenting key geochemical evidence for the likely age and facies of the source of this oil. A comparison is then made between the Bualuang Field oils and other oils from the immediate surrounding area as well as more regionally. In addition, the oils are considered against potential Mesozoic source rocks observed in peninsular Thailand.

The molecular and isotopic analysis of the Bualuang oils show strong similarity, and origin from a carbonate facies (probably marly) as indicated by dominance of C₂₉ hopane over C₃₀ hopane, presence of significant C₃₀ 30-norhopane, abundance of C₂₄ tetracyclic terpane and low amounts of diasteranes. Furthermore, the oils are believed to have a marine origin due to the presence of C₃₀ steranes (confirmed by GC-MS-MS), a C₂₆/C₂₅ tricyclic terpane ratio in excess of 1, and the stable carbon isotopic composition. The source of the Bualuang oil is considered older than Tertiary because of the absence of oleanane (typically significant in Tertiary oils), the dominance of 27-norcholestanes (24-norcholestane ratio ca.0.18) and a low C₂₈/C₂₉ sterane ratio (0.58-0.65). Correlation with other oils near Bualuang indicates that this source facies extends further north, with some subtle differences. More regionally clear differences can be observed between the Bualuang oils and other Tertiary oils recognized as either lacustrine or terrestrial in origin. The current study confirmed Jurassic-aged potential source in shales in peninsular Thailand; however, these are quite different to the source for the Bualuang oil. Previous published data for Cretaceous-aged potential source rocks onshore also do not provide a strong correlation.

Importantly this paper provides strong, albeit indirect, geochemical evidence for an additional oil-prone source to consider within the western Gulf of Thailand, which is believed to be Mesozoic in age. One of the key exploration challenges is related to identifying the presence and extent of such a Pre-Tertiary source on seismic data.

This paper describes a detailed geochemical evaluation of the Paleozoic source rocks in the Chotts basin- Southern Tunisia. Cutting samples collected from Middle Ordovician Azzel Formation (Fm), Late Silurian-Early Devonian FegaguiraFm and Permian ZoumitFm were analysed using Rock-Eval pyrolysis, GC and GC/MS techniques.

The FegaguiraFm is the principal petroleum source rock (SR) in the basin with Total Organic Carbon (TOC) values ranging from 1 to 20%. The Petroleum Potential (PP) and the Hydrogen Index (HI) values average 8 kg HC/t rock and 225 mg/g of TOC respectively indicate that the sediments have oil and gas generating potential. The terpanes series are dominated by the tricyclic and tetracyclic terpanes comparatively to hopanes with C23, C24 and C21 tricyclic terpane as prominent compounds. The diasterane contents are relatively high confirming the shaly character of the SR.

The Azzel shales has poor to moderate, occasionally good, potential for sourcing oil and gas with TOC and PP values varying from 0.80 to 4.49 % and from 0.68 to 9.20 kg of HC/t rock respectively. The HI values of 95–165 mg S2/g TOC and Tmax value of 435–448°C indicate mainly mature oil-prone kerogen. The biomarker features are characterized by high proportion of tricyclic terpanes that are dominated by C23 and C21 tricyclic terpanes. The hopanes fraction is dominated by C29 and C30 hopanes. The diasterane content are relatively high supporting the shaly character of the SR.

The ZoumitFm shows fair to excellent TOC ranging from 0.06 to 6.84% and fair to good PP (reaching 4.77 kg of HC/t of rock) and both HI and Tmax values indicate mainly immature oil-prone kerogen. The biomarker analysis reveals a low content of trictyclic terpanes relative to pentacyclic terpanes. The content of C29 and C30 hopane is relatively high. The diasteranes are present in moderate to high proportions and are less abundant than regular steranes. These biomarker features indicate a marine OM associated with marly to argillaceous limestone SR, deposited in suboxic, normal salinity depositional environment.

Summary

Genetic-specific biomarker ratios and carbon isotopes of Williston Basin produced oils were used to identify three oil families derived from Mississippian carbonate source rocks. Multivariate statistical analyses of these geochemical parameters provided information on source rock type, depositional environment and oil thermal maturity. These carbonate families differ due to algal sterane distributions and stable carbon isotopic compositions. Family 3 oils are sourced from the most carbonate-rich facies and have the highest sulfur content, while Family 2 oils were generated from more of a ‘marl' facies. Family 1 is intermediate with respect to source rock lithology. The most mature oils of Family 1 & 2 tend to be associated with Williston Basin depocenters. Oil Family 3 members are the least thermally mature. Family 1 oils are generally located along an east to west trend in northern ND and MT while Family 2 oils occur in a north to south trend along the ND and MT border. Family 3 oils predominantly occur in Saskatchewan. Three Madison oil families suggest three discrete Madison source horizons and more exploration opportunities, especially for unconventional resources.

Naturally occurring seafloor hydrocarbon macro-seeps are important indicators in deepwater exploration programs. They provide strong evidence for the presence of a working petroleum system and in theory should provide insight into the contents of the subsurface reservoir, its relationship with previously discovered hydrocarbons, and some of the characteristics of the source rock that generated the oil, all before any wells are drilled. However, in practice the hydrocarbons need to be relatively intact and free of any chemical interference to accomplish these tasks and this is not always the case. There are many physical, chemical, and biological processes in the marine environment that can obscure, diminish, or destroy the geochemical information carried by seeped hydrocarbons. In the light hydrocarbon fraction (C1-C4), microbial processes such as anaerobic oxidation of methane and methanogenesis can alter both the composition and isotopic signature of the seeped gases. For the high molecular weight hydrocarbons (C12+), their concentration is an important consideration. At low concentration, these hydrocarbons can be diluted by contributions from recent organic matter, reworked source rock organic matter, and transported hydrocarbon seepage. At higher concentrations, biodegradation of the high molecular weight hydrocarbon fraction may alter or completely eliminate the biomarker compounds used in deciphering the characteristics and source of the seeped oil.
This report will discuss methods used to recognize these interferences with the geochemical information contained in seafloor macro-seepage and how best to distinguish the seep's geochemical signal from the background geochemical noise. Application of these techniques should greatly enhance the ability to utilize hydrocarbon seep data for maximum benefit.

Abstract

The Central and Meridional Atlas of Tunisia, contains significant accumulations of oil in early Cretaceous aged reservoirs. The active cretaceous hydrocarbon system is a product of unique paleogeographic and tectonic events that led to cretaceous deposition of organic-rich source rocks.
The analysis of different sources rocks from the Central and Meridional Atlas of Tunisia indicates that the Albian Lower Fahdene Fm has a substantial oil-generation potential. The Cenomanian-Turonian Bahloul Fm exhibits fair to high organic matter content and petroleum potential and is immature to mature.The Jurassic source rock, located in the Southern part of this area, exhibits fair to good organic matter content and petroleum potential.
Molecular characterization indicates that most of the produced oils appear to be sourced from a predominantly shaly marine and mature source rock deposited in suboxic to oxic environment. Oil stains located in the northern part of the area seems to be sourced by a marly or argillaceous limestone. Oil-oil correlations and molecular characteristics of selected source rock samples and maturation models suggests that oils were generated from similar source rock and/or organic facies. The Lower Fahdene Fm is the best source candidate to generate these fluid samples. The integration of benzocarbazoles as geochemical molecules tracer has permitted a relative estimation of the lateral migration distance for the different accumulations of the area.

Introduction

The hydrocarbon exploitation in Central Atlas of Tunisia started in 1968 and has been restricted to the Douleb, Semmama and Tamesmida oil fields. Recent drilling in this area has shown some hydrocarbon shows in the Lower Cretaceous series. In spite of the long history of exploration and production, few geochemical investigations were performed until now.
The main objective of this study is to highlight the petroleum system in the Central Atlas of Tunisia. Rock Eval, Light fraction, saturates and aromatics biomarkers techniques were performed in order to assess oil occurrence and geochemical characteristics of the source rocks. The integration of previous available geochemical data about source rocks and recovered or produced hydrocarbon samples allowed us to locate the paleo and recent kitchen areas and to retrace the hydrocarbon migration routes. This study was followed by basin modelling to underline more information on the infilling history of the area.

Abstract
Unlike the petroleum which has been awaking the attention of the Romanian scientists since the end of the XIX-th century (Pilide,C.L.-1877, Cobalcescu,G.-1887) and the beginning of the XX-th century (Poni,P.-1900-1901 Edeleanu,L.-1907), geo-chemistry have been developing since `80 years and especially after 1990, when theoretical considerations joined modern technologies for oil and rock analyses.
Today we are at the same level like similar laboratories in the world because of the results obtained with the new generation tools.
There are relatively little geochemical information published in the last years on the characteristics of oils and their potential source rocks from Romania. This paper presents the first detailed data for oils from the western part of Romanian Getic De-pression. It used gas-chromatography-mass spectrometry to obtain various biomarker ratios and isotopic analysis.
The Getic Depression constitutes the Tertiary foredeep developed in front of the Southern Carpathians and it lies from Dam-bovita Valley (in the east) to the Danube River (in the west), whereas in the south, down to the Pericarpathian Fault which delimits it from the Moesian Platform. For this work we selected the western part of Getic Depression between Jiu River (West) and Cerna River (East). 57 oils were analyzed after the fractionation into saturated hydrocarbons, aromatic hydrocarbons and nitrogen, sulfur and oxygen (NSO) compound fractions, in order to get the distribution of the biomarkers.
The results of these investigations were been evaluated and interpreted using the new PC Soft: IGI. We characterized the vari-ous oil families in more detail, observing a special and interesting case of one of the analyzed fields (Ticleni) and we say now, that we better understand the petroleum system in the studied area.

Introduction

The Getic basin developed as a narrow sedimentary basin, elongated along the west-east trend, caught between the Southern Carpathians Orogene in the north and the Moesian Platform in the south (Fig.1).
The tectonic evolution of the Getic Depression was marked by the two large geological units' permanent tendency of drawing nearer, through a northward continuous subduction movement of the Moesian Platform underneath the Southern Carpathians Orogene. Throughout its tectonic evolution, since the moment of its formation as a sedimentary basin, in the Eocene, the Getic Depression has known three significant orogenesis phases: Savic, Styrian and Moldavian.
At the end of the Oligocene, the first phase of tectonic movements took place - Savic orogenesis phase - in the Getic Depression.
Savic orogenesis phase brought about the folding of the Eocene and Oligocene deposits, building up the tectonic framework whereon the structures of newer Miocene and Pliocene deposits were formed.
After the Upper Burdigalian, the older uplifts, originated from the Savic orogenesis were re-activated in the Styrian orogenesis phase.