Active Petroleum System Research Articles

E&P Notes (October 2020)

E&P Notes (October 2020)

Seismic impedance inversion and attribute analysis for reservoir characterization in an offshore depobelt, Niger Delta, Nigeria

The task of minimizing pitfall in quantitative reservoir assessment and evaluation is an integral aspect of any promising petroleum exploration and evaluation project. The Niger Delta oil province in Nigeria is chiefly composed of several pay zones with many stratigraphic intervals of sand and shale formations in varying proportion. Whereas conventional seismic interpretation technique poses certain degree of uncertainty in reservoir characterization, seismic inversion constraint by log data brings significant improvement in interpretation that reduces uncertainty in the delineation of reservoir characteristics, volume and distribution. In this present study, post-stack seismic inversion and seismic attributes analysis were used to evaluate the potentials and prospects of mapped reservoirs in a field, offshore depobelt, Niger Delta. The implementation of the tasks consists of mapping of structural framework, horizon picking, log editing and correlation, wavelet extraction, building of low-frequency model, acoustic impedance inversion and crossplot analysis of reservoir properties and attributes. A hybrid approach (formulated using Greenberg-Castagna equation) specific for the Niger Delta depobelts was used to estimate and generate shear wave velocity for the wells. Results obtained from inversion depict an acoustic impedance values in the range 150–280 ft/s g/cc and $$V_{\text{P}}/V_{\text{S}}$$ of 1.25–2.50 at a depth range of 9250–9280 ft within the hydrocarbon-bearing sands in the two wells. Region of low acoustic impedance (representing high reservoir porosity) coupled with a corresponding low $$V_{\text{P}}/V_{\text{S}}$$ ratio (indicating hydrocarbon accumulation) is presumed to have high prospects for exploration and well development. Altogether the degree of correlation between the inverted and actual impedance was found to be about 90% across the wells. It is evident that the acoustic impedance slice at 3000 ms depicts low acoustic impedance sand within 18,500–20,000 ft/s g/cc at the northeastern and southeastern regions of the field. High reflection amplitudes (bright spots) signifying hydrocarbon accumulation are also revealed on seismic attribute maps with surrounding shale diaper as the source rock. This study has revealed the prospect (i.e., existence of active petroleum system of probable economic value) of the delineated field in the Niger Delta depobelt.

Geochemical evaluation of Khami Group oils in the South Dezful Embayment, Iran

An integrated geochemical study, including GC, GC–MS and stable carbon isotope analyses, was conducted on a suite of oil samples from the Khami Group reservoirs to provide new insights into the Upper Jurassic–Lower Cretaceous petroleum system in the South Dezful Embayment. Possible source rocks were also characterized using Rock–Eval pyrolysis to address the likely potential source rocks. The oil samples representing four major reservoirs (Surmeh, Fahliyan, Gadvan and Dariyan) constitute a single genetic oil family according to bulk and biomarker parameters. High API (> 38°), highly saturated hydrocarbons (Sat > 65%), very low asphaltene content (Asp < 2%) and raised saturates/aromatics ratio (Sat/Aro > 2) are the bulk diagnostic characteristics of the studied oils implying more dominant terrigenous nature of the precursor organic matter. The predominance of C29 regular steranes (~ 40%), presence of C29Ts as well as very low gammacerane (< 10%) and moderate C35/C34 homohopane (< 1) are consistent with the mixed marine–terrigenous dysoxic organic matter input. The oils are assumed to be originated from Early Cretaceous source rocks at the peak of the oil generation window in a kitchen area located to the south of the studied region (i.e., the Binak–Borazjan Trough). The hydrocarbons were migrated from this kitchen to the structurally shallow-seated reservoirs in the center and west of the Kharg-Mish local paleo-high. The Khami Group reservoirs are not effectively sealed by the thin Hith anhydrites, and the Kazhdumi Formation finally trapped the migrated hydrocarbons. This study improves our knowledge regarding one of the active petroleum systems in the South Dezful Embayment, enhancing petroleum exploration success by navigating further drillings into the more prosperous targets.

Cretaceous geology and tectonic assembly of Jamaica

Abstract This paper provides new data on the Cretaceous geology together with existing data to define four terranes for the Cretaceous of Jamaica. The Northeast Blue Mountain Terrane (NEBMT) contains a shallow-water pile of Campanian basaltic and andesitic lavas interbedded with shallow-water, rudist-bearing limestones. The Southeast Blue Mountain Terrane (SEBMT) contains plume-related basalts attributed to the Caribbean Large Igneous Province (CLIP) of Turonian–Coniacian age overlain by interbedded cherts, limestones and basalts with CLIP affinity of Coniacian–Campanian age; the overlying succession is provisionally attributed to the late Campanian to Maastrichtian. The Western Blue Mountain Terrane (WBMT) contains a suite of Campanian arc rocks intruded by granodiorites which have tectonic contacts with metamorphic rocks (high pressure–low temperate blueschists, amphibolites and greenschists). The Western Jamaica Terrane (WJT) contains a suite of volcanic arc rocks in the Valanginian–Hauterivian, Barremian, Turonian, Santonian to Campanian, and Maastrichtian to Paleocene. These rocks are interbedded with thick to very thick (up to several kilometres) sedimentary sequences which occur at outcrop and in hydrocarbon exploration wells. Three major unconformities are present in the WJT, at the bases of the Crofts Synthem (earliest Campanian), Kellits Synthem (late Campanian to early Maastrichtian) and Yellow Limestone (late Paleocene to early Eocene). The NEBMT and SEBMT are separated from the WBMT and WJT by a NE–SW, left-lateral transform fault that defined the edge of the Caribbean Plate from the early(?) Cretaceous to the mid Eocene and allowed the Cuban oceanic arc and eastern Jamaican terranes to be emplaced between the Americas. Metamorphism in the WBMT indicates the existence of a northeasterly dipping subduction zone which allowed the subduction of CLIP lithosphere in the Campanian. Rudist bivalves suggest an affinity between Jamaica and the Siuna (Chortis) and Guerrero (Mexico) terranes in the Lower Cretaceous, suggesting that these arcs were close together. Subsequently, the three unconformities record interactions between the Jamaican arc segment and the Chortis Block and finally the collision with the Jamaican arc segment with the Maya Block in the Paleocene. The petroleum geology of each Cretaceous terrane is reviewed in the context of source and reservoir rocks. Possible source rocks exist in the Jurassic under northern Jamaica, the Albian to Turonian interval, which is associated with oceanic anoxic events, and the Maastrichtian, which contains thin units of organic-rich shales. Reservoirs are largely confined to limestones which preserve porosity in the body chambers of rudist bivalves and which have also been locally dolomitized and fractured (increasing both porosity and permeability). Oil-associated gas seeps present at outcrop, and oil shows of Jurassic and Cretaceous age from exploration wells indicate the existence of active petroleum systems, but not necessarily of economic hydrocarbon accumulations.

Rock-Eval analysis and organic petrographical characterization of the Upper Jurassic Naokelekan Formation, northern Mesopotamian basin, Kurdistan Region-Iraq

The aim of this study is to assess the type, thermal maturity and the petroleum generation potential of the Upper Jurassic Naokelekan Formation, occurring across the Kurdistan Region of Iraq, by applying organic petrographical methods and Rock-Eval analysis. The Rock-Eval data would indicate the presence of kerogen types III, IV and II as the main constituents. However, the qualitative petrographical evaluation revealed that the main organic constituents are solid hydrocarbons, in the form of microgranular migrabitumens, with minor amounts of pyrobitumens. These secondary particles have affected the results of the Rock-Eval analysis and would have led to misinterpretation of organic matter typification based on pyrolysis results only. The combined results of petrography and pyrolysis indicate an active petroleum system within the Upper Jurassic sequence, where hydrocarbons are generated and reservoired within suitable lithologies.

Play distribution and the hydrocarbon potential of the Mannar Basin, Sri Lanka

The Mannar Basin is a frontier failed rift basin between India and Sri Lanka. The Sri Lankan part has an area exceeding 42,000 km2. Although the recent two gas discoveries have confirmed the existence of an active petroleum system in the Mannar Basin, a major portion of the basin is still poorly explored. This article summarized the progress of current exploration activities and the hydrocarbon potential of the Mannar Basin. This basin began to evolve since the Upper Jurassic and experienced two rifting events; an early Late Jurassic syn-rift phase associated with East–West Gondwana break up; and a later, earliest Cretaceous syn-rift phase associated with Antarctica separation from greater India around 142 Ma. Rifting was followed by a post-rift phase comprising a thermal sag period and an inversion period. Three potential source rocks intervals have been interpreted at Maastrichtian–Campanian, Albian–Aptian, and Late Jurassic stratigraphic levels. The basin modelling work has confirmed that (1) mature potential source rocks (mainly Type II) exist below the Maastrichtian–Campanian strata and (2) the best potential source rocks (mainly Type II) exist at Albian–Aptian stratigraphic levels. The Late Jurassic source rocks have more potential for gas, while other sources have potential for both oil and gas. According to basin modelling results, Maastrichtian–Campanian and Albian–Aptian source rocks reach the oil window in the present-day depocentre around 45 Ma and 80 Ma, respectively. The Late Jurassic source rocks (mainly Type III) reach the gas window around 112 Ma in the present-day depocentre. Five play levels were defined for the whole stratigraphic section of the Mannar Basin. Tertiary play level is dominated by submarine fans, mounds and rollover anticline like structures. The Upper Cretaceous play is dominated by forced-fold structures, intra-basalt turbidite sands, and sub-volcanic sand-rich systems. The Lower Cretaceous play is dominated by reefs and abrupt margin pinch outs. The Upper Jurassic play is dominated by abrupt margin pinch outs. The Basement play consists of weathered basement rocks. The main challenge of the Mannar Basin is imaging below the flood volcanic layer, which inhibits the penetration of seismic energy and results in low-quality seismic data. Therefore, hydrocarbon potential assessments have become a major challenge below the Upper Cretaceous. The interpretation shows that the basin has a low risk for the source and reservoir, and high risk for seal and traps. New exploration activity would unlock more potential areas for hydrocarbon accumulations. Finally, the findings of this study can help for better understanding of hydrocarbon potential areas and current progress of exploration activities in the Mannar Basin, Sri Lanka.

Interpretation of Magnetic Data for the Determination of Geological Structures in Southern Part of the Cuvette-Centrale Sedimentary Basin

The Democratic Republic of Congo is willing to develop its natural underground resources in sight to increase its economy. Tothis end, the oil and gas potential of its sedimentary basins is now the new target. Into the Cuvette-centrale sedimentary basinseveral exploration works were carried out since 1950s. Among these works we have the magnetic survey done in 1980 yearwhich provided us the data used in this paper. The source rocks as well as the potential reservoir rocks and some oil seeps thathave been recognized in this gigantic basin encourage researchers to find favorable geological structures for the accumulation ofhydrocarbons in this sedimentary basin. Indeed, it is for this purpose that we have been interested to determine the regionalgeological structures in the southern part of this basin from magnetic data. After analysis, processing, and interpretation of thedata, it found that the Kutu, Oshwe, Bagata, Bulungu and Idiofa areas contain geological structures contributing to the confirmation of the existence of an active petroleum system. Concretely, on one hand and from the shape of the crystallinebasement we arrived to determine several faults and folds that can be taken as the excellent hydrocarbon traps and on the otherhand, ditches that are privileged and favorable environments for the maturation of source rocks.

Hydrocarbon seeps from the unconventional petroleum system of the South Portuguese Zone, Portugal

The presence of natural hydrocarbon seepage in the surface (soil–water) system can provide strong evidence (pathfinder) of an active petroleum system, as well as critical information on source, maturity and migration pathways. The South Portuguese Zone (SPZ) is located in the southernmost sector of the pre-Mesozoic Iberian Variscan Chain, which is composed of Carboniferous interbedded shales and greywackes, commonly displaying low-grade metamorphism. For this study, the sampling area was selected based on geological features such as alignments, faults, thrust zones, and major fold structures. Twenty-seven soil samples and 31 water samples from artesian wells, boreholes and springs were collected using specific headspace containers (Isojar®). From the geological prospecting point of view, the presence of thermogenic hydrocarbon gases in SPZ formations is clear and evident. They are present in both soil and water in significantly high levels, especially in the fault/fracture zones, with light hydrocarbon (C1–C5) values reaching more than 1500 mg/L in soil samples. Anomalous presence of some gasoline-range hydrocarbons (such as toluene) was also detected. The integration with total organic carbon, vitrinite reflectance, Rock-Eval pyrolysis and GC-IRMS data from Paleozoic rocks suggests the presence of a senile unconventional petroleum system.

Characterization of natural hydrocarbon seepage in the South Caspian Sea off Iran using satellite SAR and geological data

Two groups of oil slicks have been repeatedly detected in the Southern Caspian Sea, off Cape Sefidrud and close to the Iranian coast of the sea on the synthetic aperture radar (SAR) images acquired by the Sentinel-1A and Sentinel-1B satellites in April–June 2018. Analysis of the SAR images together with bathymetry, geological and geophysical data in geographic information system showed that these manifestations (oil slicks) visible on the sea surface have natural origin, related to the bottom seepage phenomenon and are associated with existing hydrocarbon system. Oil slicks are concentrated over the continental slope and related to local geological formations of the sedimentary cover having oil deposits related to paleo-delta of Sefidrud River. Our evidence shows that two seeps in this area are active and repeating. It is concluded that the SAR is an excellent tool for monitoring of seepage phenomenon. Moreover, results indicate that the use of remote methods to identify offshore natural oil seeps related to existing active petroleum system can be considered as a well-accepted approach to support oil and gas exploration in frontier areas such as the South Caspian Basin.

Identify the Oil Seepage in Plantungan Geothermal Manifestation, Kendal Using HVSR Method

The presence of oil seepage to the surface indicates that at least an active petroleum system is present subsurface. Oil seepage that occurred in Plantungan, Kendal, Central Java, has been known since 1971 and still produces seepage until today. On the research area, three oil seepages point were found. Plantungan region is located in East Serayu Zone underlain by volcanic area, and based on the Geology Map, the research area is located in Banjarnegara-Pekalongan Sheet. To understand the geology condition of the research area, a subsurface mapping is needed, even though the mapping does not provide the depth of bedrock and reservoir, data recording using HVSR (Horizontal to Vertical Spectrum Ratio) method that has been done in 18 points is able to provide Vp and density profile to understand the distribution of oil seepage. The oil seepage is most prominent close to SB09 location, however the result from crossplot found that the value of highest Vp×density is on SB12A with 4,306,197 kg/m2s, and lowest Vp×density in on SB17A with 302,305.3 kg/m2s.

Signatures of key petroleum system elements: outcrop examples from the Anambra Basin, Southeastern Nigeria

Although several works have proved the existence of oil and gas in the Campanian to Maastrichtian strata of the Anambra Basin, it is still considered a frontier basin due to the challenges associated with interpretation of stratigraphy and structure arising from non-availability of subsurface data. This has led to poor understanding of the petroleum system and hindered exploration activity within the basin. This research paper aims to discuss the signatures of essential petroleum system elements, based on the study of high-quality outcrop examples. Detailed field studies reveal the presence of source, reservoir and seal rocks, and traps exposed within the four lithostratigraphic units outcropping in the basin, across the southeastern part of Nigeria. The shales of Enugu Formation, offer good source rocks. The shales, coals, coaly shales and sandstones with repeated occurrence of shale–silt–sand heteroliths of the Mamu Formation provide possible source and reservoir rocks. Thick extensive sandstones with clay laminae of the Ajali Formation offer potential reservoir that are partly compartmentalized. The shales with interstratified sandstone of the Nsukka Formation provide potential cap and overburden rocks. The presence of anastomosing fracture bands, extensional joints and faults, small-scale growth faults, and rollover anticlinal structures are good evidence of structural and stratigraphic configuration that could allow for possible migration, accumulation and entrapment of hydrocarbon. These recognized signatures of the key elements of a petroleum system and oil seeps encountered in the basin are an indication of the presence of an active petroleum system.

A Paleozoic-sourced oil play in the Jura Mountains of France and Switzerland

Abstract The Jura region of France and Switzerland has significant hydrocarbon potential. This arcuate fold-and-thrust belt, located in front of the Western Alps, is composed of Mesozoic rocks, which overlie the North Swiss Basin Complex filled with Permo-Carboniferous sediments of Late Westphalian–Lower Permian (Autunian) age. The existence of three small producing gas fields, and the presence of recorded oil and gas shows in a number of petroleum wells, indicate the presence of an active petroleum system. Shows occur in stratigraphic horizons that lie beneath the regional Triassic evaporite seal. Very effective Permo-Carboniferous oil-prone source rocks include algal organically rich Autunian shale beds and Stephanian-aged bituminous shales. Carboniferous and Permian coals are also present, which would be excellent sources of gas. The primary reservoir target is the fluviatile Triassic Bunter Sandstone Formation, which is widely developed across the area and thickens to the NE. Reservoir quality is best developed in the cleaner channel sands. The La Chandelière oil field, discovered in 1989 by Exxon, is crucial evidence of the oil potential and trapping mechanism. Geochemical analysis demonstrates that the 41° API oil at La Chandelière is derived from Lower Permian Autunian shales. The trapping mechanism, interpreted from seismic and confirmed by structural modelling, is that of an unreactivated Mesozoic-aged structural high bounded by thrust faults, resulting in a large-scale rollover within the core of the structure. This combination of critical elements sets up the Paleozoic-sourced oil play within the Jura Mountains of France and Switzerland. The Jura is not generally regarded as a major petroleum province. It is a region of complex structuring and mountainous terrain. Switzerland, a country renowned for its beautiful mountain scenery, has no major oil and gas discoveries. However, this poorly explored region has active petroleum systems with good hydrocarbon shows and a number of small gas fields demonstrating hydrocarbon generation. Good-quality source rocks and excellent reservoir development have been proven by drilling, and seismic interpretation has demonstrated the existence of large closures at reservoir level. The La Chandelière oil discovery, in the French Jura, proves the presence of a Paleozoic-sourced oil play.

Petroleum systems in Southeast Asian Tertiary basins

Productive Tertiary basins in Southeast Asia have essentially similar geodynamic developments, and share many hydrocarbon habitats and active petroleum systems. In order to facilitate understanding of the essential elements that contribute to the success of petroleum systems I have classified them into a number of groups or ‘associations’ according to their sedimentary facies. This facilitates use of them as valuable analogues. Five such facies associations, containing characteristic and distinct petroleum parameters have been recognised: (i) lacustrine (ii) paralic (iii) open marine shelf (iv) deeper marine and (v) pre-Tertiary. They belong to particular cycles or stages in basin development that provide the context within which the depositional environments and palaeogeography evolve. Lacustrine facies typify the early stages of synrift development in basins closer or more proximal to the Sundaland province in northern and western SE Asia. Open marine facies, on the other hand, typify the early postrift period and basins in palaeogeographically more distal areas, such as eastern Indonesia and The Philippines. Paralic and bathyal facies characterise the later stages of the synrift and postrift cycles and are widespread throughout the proximal and intermediate parts of the area. Pre-Tertiary source facies, which provide charge in parts of eastern Indonesia and Thailand, are mainly terrestrial in nature. These differences have important implications for petroleum occurrence, which can be summarised accordingly: • More proximal basins are dominated by lacustrine to paralic facies in the synrift cycle and have a mainly non-marine sedimentary fill. Petroleum systems with oil charge are dominant. • More distal basins are dominated by rapid postrift subsidence. In the open marine facies carbonate reservoirs are well-developed, while petroleum systems are mainly gas-prone. • Around Borneo thick late postrift passive margin delta sequences with oil- and gas-prone coaly source rocks and clastic reservoirs are developed in delta-top environments. Transported terrigenous organic material is commonly found in related deep marine environments and contributes to a marine source facies. Both give rise to prolific petroleum systems. • Many basins in the Sunda Shelf area lie in an intermediate situation, where a non-marine synrift is followed by a marine postrift cycle. Such basins benefit from lacustrine and paralic source rock and reservoir sequences in both the syn- and the postrift, and are often characterised by multiple petroleum systems. Evaluation of petroleum potential in Southeast Asian Tertiary basins requires a special approach: in most parts of the World, such as the Middle East and Northwest Europe, source rocks are of marine origin, are relatively consistent in type and quality and are located in well-defined formations of regional extent. In SE Asia the terrestrial and lacustrine source rocks are more difficult to locate, are variable in quality and are often distributed in thin beds throughout thick sequences. These differences mean that predictive extrapolations of charge quality and maturity, and therefore of basin prospectivity, are much more difficult in Southeast Asia: This probably explains why discoveries continue to be made after almost 130 years of exploration!

A giant oil seep at a salt-induced escarpment of the São Paulo Plateau, Espírito Santo Basin, off Brazil: Host rock characteristics and geochemistry

An international research cruise named Iatá-Piuna took place on the São Paulo Plateau on May 2013 in the Campos and Espírito Santo basins, off Brazil. The cruise was carried ou on board the research vessel (R/V) Yokosuka that hosts the human operated vehicle (HOV) SHINKAI 6500. It aimed at finding chemosynthetic communities, composed of organisms capable of generating their own vital energy by metabolizing organic and inorganic compounds related to seeps. Identification of these organisms could provide information for understanding the origin of life, since they may resemble primitive organisms that existed in the initial stages of life on Earth. During Leg 2 (May 10–24, 2013), however, dives on the northern part of the São Paulo Plateau at the Espírito Santo Basin led to the discovery of a giant oil seep. The seep, ca. 3 nautical miles (ca. 5.6km) in length is located along an outcrop of Eocene rocks on a salt-induced escarpment of the plateau and at a water depth of ca. 2700m. The 200m relief of the seafloor suggests that the seep takes place along an active fault system driven by salt diapirism. The oil was analyzed and identified as a severely biodegraded marine oil, generated by carbonate rocks within a minibasin located to the east of the escarpment. This represents valuable exploratory information because it proves that an active petroleum system is present in the context of minibasins associated with salt diapirism in the area.

Geochemical correlation of Asmari/Jahrum reservoir of Nargesi oilfield with seeps nearby

ABSTRACT In case of maintaining the reservoir pressure by gas injection, connection between the reservoir and oil seeps around the oilfield should be investigated. Existence of probable conduits from reservoir to surface would cause problems such as environmental issues and capital losses. Comprehensive geochemical analyses were performed on Nargesi oilfield and nearby seep samples in order to investigate their geochemical correlation. Biomarker and diamondoid distributions as well as stable carbon isotope analysis on selected samples were determined by GC-MS and Finnigan Delta Plus mass spectrometer, respectively. Two active petroleum systems were identified in the region. A Jurassic petroleum system charged Nargesi oilfield, whereas the seeps appear to be charged by an older petroleum system. Higher maturity of seep samples identified by methylnaphthalenes, trisnorhopanes, and triaromatic steroid ratios implied that the second petroleum system should be older than Jurassic. Biomarker ratios confirmed that Marl-Carbonate source rocks deposited under anoxic to dysoxic conditions in open marine environment were the main oil-generating facies for the oilfield. Diamondoid indexes further support the concept developed by biomarker data and reveal that the seeps should be probably charged by shaly source rock. The negative correlation implies that gas injection would be effective.

New insights into the North Taranaki Basin from New Zealand’s first broadband 3D survey

The Taranaki Basin is the only hydrocarbon producing basin in New Zealand. The North Taranaki Basin has widespread two-dimensional (2D) seismic coverage and numerous wells that have not encountered commercial accumulations. This is attributed to the structural complexity in the central graben and the absence of necessary information to help understand the basin’s evolution. An active petroleum system has been confirmed by hydrocarbon shows and non-commercial oil and gas discoveries (Karewa-1 and Kora-1). A broadband long offset three-dimensional (3D) seismic survey was acquired and processed by Schlumberger in 2013 to evaluate the hydrocarbon potential of the North Taranaki Basin. Innovative acquisition techniques were combined with advanced processing and imaging methods. Raypath distortions and depth uncertainty were significantly reduced by processing through tilted transverse isotropy (TTI) anisotropic Kirchhoff prestack depth migration with a geologically constrained velocity model. The survey provided the necessary information to understand the petroleum system and provide evidence for material hydrocarbon accumulations. In this investigation, we assessed the hydrocarbon potential of the North Taranaki Basin using the newly acquired data. 3D seismic interpretation and amplitude-versus-offset (AVO) analysis support the renewed potential of the basin and demonstrate effectiveness of these technologies that together can achieve encouraging results for hydrocarbon exploration.

Geochemical characterization of source rocks and oils from northern Iraq: Insights from biomarker and stable carbon isotope investigations

The origin of oil in the Cretaceous–Tertiary reservoirs of northern Iraq remains controversial. Consequently, a detailed geochemical study, including Rock-Eval pyrolysis, gas chromatography–mass spectrometry, and carbon isotope analysis was conducted on 65 source rock core and cuttings samples from the Najmah, Chia Gara, and Balambo formations, northern Iraq. Twenty-four crude oils were also analyzed to provide new insights into source organic matter, depositional environment, and correlations between crude oils and their probable source rocks.Bulk geochemical analysis of candidate source rock samples indicates that the Najmah Formation has more petroleum potential than the Chia Gara and Balambo formations. These three candidate source rocks were deposited in slightly different environments and have different organic matter types as determined by screening analysis and biomarker data. The Najmah Formation contains organic-rich (TOC up to 4.2 wt%) oil-prone type I-II kerogen deposited under anoxic conditions. The Chia Gara and Balambo formations contain mixed type II-III and type-III kerogens, oil- and gas-prone, deposited under less reducing conditions with more terrigenous organic matter input. Unfortunately, most of the rock samples contain less than 2.5 wt% TOC, which likely excludes them as source rocks, but more deeply buried equivalents may contain more organic matter.Biomarker and stable carbon isotope compositions suggest that Cretaceous- and Miocene-reservoired oils from the northern Iraq basins, although predominantly derived from marine carbonate organic matter, constitute five genetically distinct oil families. Based on age-specific biomarkers, the oils were probably derived from three active petroleum systems in northern Iraq: Jurassic, Jurassic–Early Cretaceous, and Early to mid-Cretaceous. Biomarker maturity parameters indicate that most of the oils were generated in the early oil window, similar to the extracts.

Detection of near-surface hydrocarbon seeps using P- and S-wave reflections

The combined use of P- and S-wave seismic reflection data is appealing for providing insights into active petroleum systems because P-waves are sensitive to fluids and S-waves are not. The method presented herein relies on the simultaneous acquisition of P- and S-wave data using a vibratory source operated in the inline horizontal mode. The combined analysis of P- and S-wave reflections is tested on two potential hydrocarbon seeps located in a prospective area of the St. Lawrence Lowlands in Eastern Canada. For both sites, P-wave data indicate local changes in the reflection amplitude and slow velocities, whereas S-wave data present an anomalous amplitude at one site. Differences between P- and S-wave reflection morphology and amplitude and the abrupt decrease in P-velocity are indirect lines of evidence for hydrocarbon migration toward the surface through unconsolidated sediments. Surface-gas analysis made on samples taken at one potential seeping site reveals the occurrence of thermogenic gas that presumably vents from the underlying fractured Utica Shale forming the top of the bedrock. The 3C shear data suggest that fluid migration locally disturbs the elastic properties of the matrix. The comparative analysis of P- and S-wave data along with 3C recordings makes this method not only attractive for the remote detection of shallow hydrocarbons but also for the exploration of how fluid migration impacts unconsolidated geologic media.

Tectonic Influence on Changes in Neogene Sediment Supply, Western Part of North Serayu Basin

Western part of North Serayu Basin composed of Neogene sequence; Halang, Pemali and Rambatan Formation. The oil seeps discovery in this area is an indication of the presence an active petroleum system. Active tectonic condition occur coincidence with the time of deposition. The tectonic influence on change in sediment supply will be the subject of this research. The combinations of subsidence, eustatic and sediment supply are corresponding to the accommodation space, moreover to the type of sediment which is deposited. The quantity and rate of sediment supply to the basin are closely related to the tectonic activity. In the context of Petroleum Potential, study of sediment supply will provide information about the potential source rock, reservoir and caprock that developed in the research area. During the Neogene at least there have been three times of sea level change in the research area which is related to thickening sedimentary sequence during middle of N18 and thinning in N13 to N17 in some place.

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN, OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile.Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m2. The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m2.Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.