bluuebunny/crossref_metadata_2025 huggingface dataset:
OIL AND GAS PLAYS IN ALBANIA: DO EQUIVALENT PLAYS EXIST IN GREECE?
Authors: Zelilidis A. , Piper D. J. W. , Vakalas I. , Avramidis P. , Getsos K.
Published: March 2006

Western Greece and Albania have had a broadly similar geological history and the hydrocarbon potentials of both areas may therefore be comparable. In this paper, we briefly review the stratigraphic and structural evolution of Albania and compare it with that of NW Greece in terms of source rocks, reservoirs, seals, structures and maturation history.

In Albania, a number of sizeable oilfields produce from Mesozoic‐Paleogene carbonates assigned to the Ionian Zone; traps are thrust‐related anticlines. Gas is produced from both Mesozoic reservoir rocks and also from Tortonian‐Messinian sandstones along the eastern margin of the Neogene Durres Basin. In both Albania and western Greece, the Mesozoic to Eocene succession includes organic‐rich shales which were deposited on the Apulian margin of the Pindos Ocean. Tertiary closure of that ocean resulted in thin‐skinned thrusting onto the Apulian margin along Triassic evaporite décollements. Thick, late Eocene to Miocene flysch was deposited synchronously in the Pindos foreland basin, and was deformed by the advancing thrust system.

The Neogene Durres and Preveza Basins developed on the Apulian foreland as a result of complex plate‐tectonic interactions and block rotations. NE‐trending lineaments played an important role in the evolution of these basins, and also gave rise to dip‐closed anticlines in the Ionian Zone successions in both countries. In Albania, the Vlora‐Elbasan lineament controlled the development of structural traps at producing oilfields, and the Cephalonia transform fault in Greece may have played an analogous structural role. Potential hydrocarbon plays in NW Greece, analogous to producing fields in Albania, are located in the Ionian thrust belt and in the Neogene Preveza Basin. In addition, the middle Tertiary flysch basins of both countries may have some gas potential.
THE APPLICATION OF ELECTRON SPIN RESONANCE AS A GUIDE TO THE MATURATION AND TYPING OF ORGANIC MATTER IN THE NORTH SEA
Authors: McTavish R. A.
Published: March 2006

In early electron spin resonance (ESR) analysis of North Sea wells, maturation of organic matter (OM) was expressed in terms of maximum palaeotemperature (MPT) based on North American calibrations that did not consider the influences of kerogen composition or overpressure. In the North Sea, the MPTs were anomalous in overpressured sequences and relative to other indices of OM maturation such as vitrinite reflectance, so the ESR method was abandoned there in geochemical studies. However, early empirical study of North Sea ESR data indicated that, in relation to functions that linked temperature and pore pressure, some ESR parameters were predictable without reference to MPTs.

In order to re‐evaluate ESR parameters as indices of OM maturation, the physical factors (temperature and pressure) which affect OM maturation are related in the present paper to the ESR parameters “g” (spectral position) and Ng (spin density) at six well locations in the northern North Sea. A third ESR parameter, W (line width), is not an effective guide to maturation levels due to its complex relationship to the physical factors and kerogen types. However, cross‐plots of W versus “g” and Ng appear to be as effective as pyrolysis for kerogen typing. Levels of maturation investigated in the North Sea wells range through the equivalent vitrinite reflectance values of about 0.50–1.50%. The values of “g” and Ng have been differentiated for kerogen type, but undifferentiated values of “g” have also been studied.

Regression analysis has shown that there are linear relationships between the ESR parameters “g” and Ng, and the physical factors present‐day temperature (To), “effective” temperature (Te), and differential pressure (Pd). Correlation coefficients for both “g” (undifferentiated and differentiated) and Ng (differentiated) relative to the physical factors are high; the highest values are for “g” and Ng relative to Te and Pd (r =−0.950 for “g” differentiated or undifferentiated, r = 0.944–0.976 for Ng differentiated, respectively). However, correlation coefficients were lower for “g” and Ng relative to To.

More frequent high correlation coefficients and larger sample populations suggest that “g” (undifferentiated) is a more reliable index of OM maturation than Ng(differentiated). However, the estimation of levels of OM maturation is improved if both indices are used together.

The ESR method appears to be effective both for estimating levels of OM maturation and for kerogen typing. It has a number of potential advantages over other geochemical methods: firstly, it is more sensitive for estimating OM maturation than most other methods; secondly, it can be used to analyze organic matter which is as old as Proterozoic; thirdly, it does not destroy the samples analyzed.
ORGANIC PETROLOGY OF POTENTIAL SOURCE ROCKS IN THE TARIM BASIN, NW CHINA
Authors: Liu Dameng , Tu Jianqi , Jin Kuili
Published: March 2006

Potential source rocks in the Tarim Basin (NW China) include Cambrian‐Lower Ordovician lagoonal carbonates and mudstones; Middle‐Upper Ordovician platform carbonates; Carboniferous‐Permian shallow‐marine carbonates and mudstones; and Triassic‐Jurassic continental deposits including coals and lacustrine mudstones. Our petrological observations show that the organic components in Cambrian‐Ordovician deposits are mainly alginites andamorphinites with minor vitrinite‐like macerals, zooclasts and solid bitumen (Type I organic matter). The organic carbon content of these rocks is 0.1–2% TOC (averaging 0.9%TOC in deeper‐water fades) and they are mature to overmature in terms of oil generation.

Organic macerals in Permian‐Carboniferous source rocks are dominated by alginite with minor quantities of zooclasts andexinite derived from terrestrial higher plants (mainly Type II OM with minor Types I and III). TOC contents are 0.1–1%. These rocks are mature to highly‐mature in terms of oil generation.

Macerals in Jurassic‐Triassic source rocks are dominated by vitrinite and inertinite, with V+I > 50% and alginite + amorphinite < 40%; exinite averages 2–5%. This organic matter type is Type III, and the sediments are immature to just mature.

We have calculated the original organic matter richness of Ordovician deposits at selected locations. The original OM content appears to have been particularly high around Lunnan (in the North Tarim Uplift), in the Central Tarim Uplift and around Tadong (in the SE Uplift). These areas are therefore suggested to have particularly high exploration potential.
A SEQUENCE STRATIGRAPHIC SYNTHESIS OF THE NORTH AFRICAN MESOZOIC
Authors: Carr I. D.
Published: March 2006

A synthesis of the sedimentology and sequence stratigraphy of the Mesozoic succession of North Africa is presented. Two chronostratigraphic correlation panels have been constructed at roughly right angles to each other across North Africa, in approximately E‐W and NNW‐SSE orientations. The panels illustrate the way in which sedimentology and hydrocarbon geology vary across the continent through time. The Mesozoic succession is divided into two sequences (NA 6, Early Triassic to Middle Cretaceous; and NA 7, Middle to Late Cretaceous), for both of which sequence boundaries, maximum flooding surfaces and component systems tracts are defined. The systems tracts are of tens of Ma duration and approximate to the second‐order cycles of previous publications. New palaeogeographic reconstructions for North Africa for the Triassic, Jurassic and Cretaceous are illustrated, and a new sea level curve based on the panels and palaeogeographic reconstructions is compared to other published sea level curves.
SOURCE ROCK EVALUATION AND GEOCHEMISTRY OF CONDENSATES AND NATURAL GASES, OFFSHORE NILE DELTA, EGYPT
Authors: Sharaf L. M.
Published: March 2006

Geochemical analyses of mudstones from wells in the NE offshore Nile Delta suggest that the Early Miocene Qantara Formation has “good” potential to generate hydrocarbons at the studied locations. Its generating capability and oil‐proneness increase northwards, towards areas where better organic‐matter preservation and a greater contribution from marine source material can be expected. By contrast, the Middle Miocene Sidi Salem Formation has “poor to fair” potential to generate mixed gas and oil, while the overlying Wakar and Kafr El Sheikh Formations have “poor” capability to generate gas with minor oil. Based on pyrolysis Tmax and thermal alteration index assessments, the Wakar and Kafr El Sheikh Formations are immature in the study area. The Sidi Salem and Qantara Formations are immature in the southern part of the study area, but are within the oil window in the north, around well Temsah‐4.

Biomarker distributions based on GC‐MS analyses of two condensate samples from the Wakar and Sidi Salem Formations indicate that hydrocarbons are derived from siliciclastic source rocks containing significant terrestrial material and limited marine organic matter. The condensates were generated during early maturation of Type III kerogen from deeper and more mature source rocks than those encountered in the drilled wells. Geochemical and isotopic data from natural gas produced from the Kafr El Sheikh Formation suggest mixed biogenic and thermogenic sources.
THE CONFIGURATION OF THE BASEMENT BENEATH THE ZAGROS BASIN
Authors: Bahroudi A. , Talbot C. J.
Published: March 2006

It has long been recognised that the deposition and deformation of the Phanerozoic cover in the Zagros Basin (mountains plus foreland) was strongly influenced by the reactivation of old tectonic fabrics in its basement. Facies boundaries and structures trending north‐south and NW‐SE can be attributed to the reactivation of Pan‐African sutures and Najd faults which are exposed in the Nubian‐Arabian Shield. However, to the east of a projection of the Oman line SWwards into the Rhub Al Khali Basin, cover structures have a NE‐SW trend which is not seen in Arabia. This boundary may overlie a Pan‐African suture between Arabia and India (Somalia or Pakistan).

Data including magnetic intensities, geothermal gradients and isopach maps are used here to distinguish old faults which were reactivated in the basement from more recent faults formed in the cover by Zagros shortening. Old faults trending NW‐SE are interpreted as having reactivated episodically since the Permo‐Triassic opening of Neo‐Tethys; perhaps more significantly, the basement faults that reactivated in the East Arabian Block since then trend north‐south. The basement configuration is clarified by extending a modified East Arabian Block across the Zagros to an “East Arabian‐Zagros block” in which the NW trend of the Zagros lies between two syntaxes. This suggests a new tectonic framework for the region. The repeated reactivation of basement faults throughout the East Arabian‐Zagros Block controlled source rocks, traps and seals for the supergiant and giant oil and gas reserves which are present at various stratigraphic levels in different areas.
HYDROTHERMAL LAUMONTIZATION AND MICROFRACTURE FORMATION IN RESERVOIR ROCKS AT THE YUFUTSU FIELD, HOKKAIDO, NORTHERN JAPAN
Authors: Yanagimoto Y. , Iijima A.
Published: March 2006

Reservoir rocks at the Yufutsu oil‐ and gasfield (southern Hokkaido, Northern Japan) comprise Eocene conglomerates and Early Cretaceous granitoids in which networks of fractures < 0.02 mm across are widespread. These basement reservoir rocks were fractured during normal faulting in the late Oligocene — early Miocene. In the early to middle Miocene, the fractured rocks are thought to have been permeated by acidic formation waters derived from Eocene coal measures. Laumontite (a Ca‐rich zeolite) and smectite/illite (S/I) mixed‐layer clay minerals were precipitated in the microfractures and occluded them.

The Yufutsu field is located on the western margin of a duplex structure formed during Pliocene or later shortening. As a result of this regional compression, the preexisting “early” microfractures which had been occluded with structurally‐weak laumontite and S/I mixed‐layer clay mineral aggregates reopened as “late” microfractures. Natural gas, which had been generated in deeply‐buried Eocene coal measures in the synclinal area to the east of Yufutsu field, migrated westwards and accumulated in the re‐fractured reservoir rocks.

The duplex structure in central Hokkaido probably extends to the unexplored offshore Iburioki structure to the south. Fractured reservoir rocks similar to those at the Yufutsu field may also occur at Iburioki.
DIAGENESIS OF SILURIAN REEFAL CARBONATES, KUDIRKA OILFIELD, LITHUANIA
Authors: Stentoft N. , Lapinskas P. , Musteikis P.
Published: March 2006

Upper Silurian carbonate reservoir rocks at the Kudirka oilfield, southern Lithuania, have a complex diagenetic history. This consists of the following stages: compaction and dewatering; early lithification; minor fracturing? first generation leaching; precipitation of first‐ and second‐generation inter‐ and intragranular calcite cements; recrystallization of lime mud, sparry calcite cement and bioclastic grains; chemical compaction and the formation of stylolite‐associated fractures; precipitation of dolomite, pyrite and silica; a second phase of leaching, with stylolite surfaces acting as conduits for aggressive fluids; and finally oil emplacement.

The Upper Silurian carbonates are interpreted to correspond to a variety of reefal deposits. In all the types of reef rock analysed, late diagenetic leaching has enhanced reservoir quality. However, no clear correlation could be found between rock texture and reservoir quality. This is mainly because the very common crinoid fragments acted as substrates for the growth of pore‐occluding syntaxial calcite cement. The lack of correlation between rock texture and reservoir quality can also be attributed to subordinate localized stylolite‐related dolomitization.
BURIAL HISTORY RECONSTRUCTION AND THERMAL MODELLING AT KUH‐E MOND, SW IRAN
Authors: Kamali M. R. , Rezaee M. R.
Published: March 2006

At the Kuh‐e Mond anticline (Fars Province, SW Iran) and in nearby offshore structures, large volumes of natural gas are reservoired in the Permian — Early Triassic Dehram Group while heavy oil has been discovered in the Cretaceous Sarvak and Eocene Jahrum Formations. In this paper, we use data from six exploration wells and from nearby surface exposures to reconstruct the burial history at Kuh‐e Mond. Regional observations show that the thick sedimentary fill in this part of the Zagros Basin was subjected to intense tectonism during the Zagros Orogeny, with a paroxysmal phase during the late Miocene and Pliocene. Thermal modelling and geochemical data from Kuh‐e Mond and adjacent fields allows possible hydrocarbon generation and migration mechanisms to be identified. Maturities predicted using Lopatin's TTI model are in accordance with maturities obtained from vitrinite reflectance measurements.

We show that formations which have source potential in the nearby Dezful Embayment (including the Pabdeh, Gurpi, Gadvan and Kazhdumi Formations) have not reached the oil window in the Mond wells. Moreover, their organic carbon content is very low as they were deposited in oxic, shallow‐water settings. Underlying units (including the Ordovician and Cambrian) could have reached the gas window but contain little organic matter. Silurian shales (Sarchahan Formation), which generate gas at Kuh‐e Gahkum and Kuh‐e Faraghan (north of Bandar Abbas) and in Saudi Arabia and elsewhere in the Middle East, are absent from the Mond structure.

The absence of source rocks suggests that the gas and heavy oil accumulations at Kuh‐e Mond and at nearby fields have most probably undergone long‐distance lateral migration from distant source kitchens.
MESOSCALE HETEROGENEITY OF FLUVIAL‐LACUSTRINE RESERVOIR ANALOGUES: EXAMPLES FROM THE EOCENE GREEN RIVER AND COLTON FORMATIONS, UINTA BASIN, UTAH, USA
Authors: Taylor A. W. , Ritts B. D.
Published: March 2006

The Eocene Uinta Basin of Utah is a dominantly lacustrine basin that affords the opportunity to survey analogue sandstone reservoirs developed within and adjacent to the lacustrine system. From its SW to NE margin, Eocene strata in the Uinta Basin record fluvial, deltaic, profundal lacustrine, and wave‐dominated shallow‐lacustrine environments. Of these depositional systems, analogue sandstone reservoirs are well‐exposed in outcrop in the fluvial‐deltaic and wave‐dominated intervals. Field and petrographic examination of selected fluvial‐lacustrine reservoir analogues are used to document the mesoscale facies architecture and heterogeneity. Complex depositional geometries and heterogeneity exist at a variety of scales, both within single subenvironments and between opposite sides of the basin.

Three outcrops in the Uinta Basin were studied. Outcrops One and Two are located in the SW portion of the basin in Nine Mile Canyon, and represent the interface between fluvial rocks of the Colton Formation and dominantly lacustrine strata of the Green River Formation. Outcrop Three is located at Raven Ridge in the NE of the basin, a shallow wave‐dominated lacustrine margin. Photomosaics and multiple vertical measured sections were described for each outcrop, and were utilized to document lithofacies assemblages, bounding surfaces, and sandbody architecture and heterogeneity. Sandstone samples from each outcrop were analyzed petrographically to capture the small‐scale heterogeneity characteristic of the three outcrops.

Sedimentary rocks at Outcrops One and Two consist of lenticular, tabular, or undulatory channel, distributary channel, and bar deposits that are partially to entirely compartmentalized, or encased, by mudstone units. These sandstone units, analogous to reservoir intervals in lacustrine basins, show various types of lateral and vertical connectivity which are dependent on the degree of amalgamation and the sand:mud ratio. Within these sandbodies, mud chip lags, large mud clast horizons, discontinuous finer‐grained beds, accretion sets and amalgamation surfaces represent internal heterogeneity which could be expected to affect transmissibility in an actual reservoir. The complex geometry and heterogeneity characteristic of these reservoir analogues confirms the need for detailed reservoir characterization studies on all scales in order to improve production efficiency in such systems.

Outcrop Three is dominated by tabular and laterally extensive offshore bar and sandsheet deposits which are separated by thick mudstone units. Large‐scale heterogeneity is minimized within these reservoir analogues, in that sandbodies exhibit excellent lateral continuity and less complex amalgamation. Therefore, documentation of heterogeneity at the bed‐ and petrographic‐scale is necessary to better address production potential in these types of reservoirs.
RESERVES/RESOURCE CLASSIFICATION SCHEMES USED IN RUSSIA AND WESTERN COUNTRIES: A REVIEW AND COMPARISON
Authors: Poroskun V. I. , Khitrov A. M. , Zaborin O. V. , Zykin M. Y. , Heiberg S. , Sondenå E.
Published: March 2006

The international oil industry currently uses a number of schemes for hydrocarbon reserves and resources classification. These serve different purposes and are used variously by Governmental agencies, oil companies, scientific societies, research institutes and by the US Securities and Exchange Commission (McKelvey, 1975; Grishin, 1993; Nemchenko et al., 1996). Although the schemes have many features in common, attention has been paid in recent years to the development of a single, universal classification (McKelvey, 1975).

Russia, unlike many other countries, uses only one reserves classification scheme (Anon., 1983; Nemchenko et al., 1996; Stasenkov and Gutman, 1989). Interest is growing in the comparison of the Russian scheme with those used elsewhere. A number of Russian oil and gas companies (e.g. Lukoil, Yukos and Gazprom) have already introduced Western standards for reserves evaluation in order to facilitate foreign investment. Conversely, Western companies operating in the Russian Federation are translating the Russian classification scheme into more familiar terms and definitions.
UPPER ORDOVICIAN CARBONATE MOUNDS ON GOTLAND, CENTRAL BALTIC SEA: DISTRIBUTION, COMPOSITION AND RESERVOIR CHARACTERISTICS
Authors: Sivhed U. , Erlström M. , Bojesen‐Koefoed J. A. , Löfgren A.
Published: March 2006

We present a multidisciplinary description of the Upper Ordovician carbonate mounds which are found throughout the central Baltic Sea and which were studied in detail on the island of Gotland. These mounds were the subject of intense exploration between 1974 and 1992 and a total of 323 shallow wells were completed in more than 100 mounds on Gotland. Many of these were put into production and a total of 100,000 cu. m of high quality oil was produced. In this paper, we discuss the mounds’occurrence, lithological characteristics, age, faunal composition, petroleum chemistry and reservoir properties.

The study is based on analyses of core material from wells in the northern part of Gotland. Upper Ordovician mound reservoirs here contain oil which has a similar geochemical signature to that in Lithuania and in the Kaliningrad district (Russia). The oil was probably derived from marine anoxic shales and migrated up‐dip from more central parts of the Baltic Syneclise where oil‐prone shales are known to occur. An intraformational origin for the oil is unlikely.

The mounds contain large numbers of vugs and moulds which communicate mainly through dissolution fractures and surfaces and probably reflect a marine regression. Various lithofacies were recognized from petrographic studies including sub‐mound, intra‐mound, cap and flank, and supra‐mound facies. Algae and stromatolites dominate the intra‐mound facies, providing an organic framework for the entire structure. Consequently, the mounds are not merely poorly defined buildups of mud and micrite, as has previously been assumed. Biostratigraphic data indicates a late Caradoc to Ashgill age for the mounds and their associated lithologies.
STRATIGRAPHIC CONTROLS ON PALAEOZOIC PETROLEUM SYSTEMS, GHADAMES BASIN, LIBYA
Authors: Dardour A. M. , Boote D. R. D. , Baird A. W.
Published: March 2006

The distribution of oil‐ and gasfields in the Libyan Ghadames Basin is strongly influenced by the stratigraphic architecture of the Silurian‐Devonian succession. This interval encompasses part of two (second‐order) super‐sequences separated by the Caledonian unconformity: (i) a late Ashgillian‐Silurian super‐sequence, comprising the Melez Chograne‐Memouniat periglacial lowstand, the Tanezzuft transgressive to early highstand shales and the Acacus Formation late highstand systems tracts; and (ii) the lower part of a composite Devonian‐Carboniferous super‐sequence terminated by the Hercynian unconformity, which includes the lowstand Tadrart fluvial‐shallow marine sands, the Ouan Kasa (transgressive) and the Aouinet Ouinene transgressive to early highstand systems tracts of Devonian age.

Hydrocarbon accumulations in Acacus, Tadrart and later Devonian reservoirs have been charged from a basal Silurian (Tanezzuft Formation) “hot” radioactive shale source rock. The Acacus and Tadrart sandstones provided regional migration conduits sealed by intra‐Acacus, intra‐Devonian (Emghaet Formation) and Permian (Bir Al Jaja Formation) shales. Regional stratigraphic continuity of these migration conduits permitted the development of low to moderate impedance petroleum systems dominated by lateral migration.

Basin reconstructions and burial history modelling suggest three expulsion peaks from the basal Tanezzuft Formation source rock, preceding major periods of Hercynian, Austrian and Alpine (mid‐late Tertiary) uplift and exhumation. Hydrocarbons trapped prior to the Hercynian event were dispersed during later periods of structural deformation. Some pre‐Austrian accumulations may have survived locally in more robust traps. However, most if not all of the oil‐ and gasfields discovered in the Late Silurian ‐ Devonian succession were probably charged during the Late Cretaceous—Early Tertiary, only to suffer partial dispersal during later uplift, tilting and flushing. Three petroleum systems can be distinguished within the basin: (i) a Tanezzuft ‐Acacus system to the north; (ii) a Tanezzuft ‐ Tadrart system to the south; and (iii) a Tanezzuft ‐Acacus/Tadrart(+) system in the centre, with some leakage into overlying Devonian and Carboniferous sandstones locally.
TEMPESTITE DEPOSITS ON A STORM‐INFLUENCED CARBONATE RAMP: AN EXAMPLE FROM THE PABDEH FORMATION (PALEOGENE), ZAGROS BASIN, SW IRAN
Authors: Mohseni H. , Al‐Aasm I. S.
Published: March 2006

The Pabdeh Formation is part of a thick carbonate‐siliciclastic succession in the Zagros Basin of SW Iran which includes carbonate reservoirs of Cretaceous and Cenozoic ages. From field observations and petrographic and facies analysis of exposures in the type section of the Pabdeh Formation, four lithofacies were recognized. These are from oldest to youngest: (i) a mottled, bioturbated bioclastic wackestone/mudstone facies; (ii) a wackestone/packstone facies with horizontal burrows on bedding planes; (iii) a thin‐bedded bioclastic wackestone/mudstone facies alternating with thin bioclastic‐oolitic‐intraclastic intervals; and (iv) a bioclastic foraminiferal / algal / peloidal packstone facies. These observations indicate that facies evolved upwards from deep outer‐ramp deposits to inner‐ramp deposits within a shoal complex, suggesting progradation of the ramp depositional system.

Storm events significantly influenced the ramp system. Storm‐generated surges transported sediments from nearshore to the deeper outer‐ramp environment where they were deposited as shell‐lags, composed mostly of bioclastic packstones, rich in pelagic microfauna with sharp, undulatory erosional basal contacts. The packstones rest on outer ramp mudstones deposited below storm base level. Sedimentary structures in the Pabdeh Formation are those typical of storm deposits, such as hummocky cross‐stratification, ripple cross‐lamination, ripple marks, escape burrows on the tops of the beds, couplets of fine‐ and coarse‐grained laminae and mixed fauna, as well as intraclasts derived from underlying facies. These distinctive sequences are interpreted to have been generated by waning storm‐generated currents. The dominance of fine‐grained sediments (medium to fine sand); the lack of large‐ scale hummocky cross‐stratification; the minor amounts of intraclasts derived from underlying facies; the paucity of amalgamated tempestite beds; and the finely‐laminated (mm to cm scale) couplets of coarse and fine lamina all suggest a distal tempestite facies. Palaeogeographic reconstruction of the Zagros Basin during the Eocene indicates that the study area was situated in tropical, storm‐dominated palaeolatitudes.
DEPOSITIONAL HISTORY AND SEQUENCE STRATIGRAPHY OF OUTCROPPING TERTIARY CARBONATES IN THE JAHRUM AND ASMARI FORMATIONS, SHIRAZ AREA (SW IRAN)
Authors: Nadjafi M. , Mahboubi A. , Moussavi‐Harami R. , Mirzaee R.
Published: March 2006

The Oligo‐Miocene Asmari Formation is one of the most important petroleum reservoir units in the Zagros Basin of south and SW Iran. It mainly consists of limestones and dolomitic limestones with interbedded shales, together with a few intervals of sandstone and gypsum assigned to the Ahwaz and Kalhur Members, respectively. The Asmari Formation rests on the thin‐bedded limestones of the Jahrum Formation (Paleocene‐Eocene). In this paper, we report on the lithofacies characteristics of these two formations using data from three measured outcrop sections near Shiraz in SW Iran. From field and petrographic data, we have identified four major lithofacies and twelve subfacies which are interpreted to have been deposited in open‐marine, shoal, lagoon and tidal flat settings.

We show that the Asmari and Jahrum Formations constitute two separate depositional sequences which are separated by a thin palaeosol, representing a type‐one sequence boundary which can be correlated with global curves of relative sea‐level. Each depositional sequence is composed of many metre‐scale shallowing‐upward parasequences. This is the first time that the Asmari and Jahrum Formations have been differentiated in the study area. We hope that this study will lead to a better understanding of the Asmari Formation in the subsurface in other parts of the Zagros Basin.
FACIES AND POROPERM CHARACTERISTICS OF A CARBONATE SHOAL (MUSCHELKALK, SOUTH GERMAN BASIN): A RESERVOIR ANALOGUE INVESTIGATION
Authors: Ruf M. , Aigner T.
Published: March 2006

Outcrop analogue investigations contribute to the understanding of the architecture and behaviour of subsurface hydrocarbon reservoirs. This study was designed to provide input for static reservoir modelling of shoal bodies on carbonate ramps.

We investigated an oolitic and shelly carbonate shoal of Late Muschelkalk (late Ladinian) age, about 30 km long and 15 km wide, exposed in a series of quarries in southern Germany. The dimensions of this shoal body correspond to both modern analogues in the Persian Gulf and to oilfields in the Middle East.

Fifteen outcrop locations were chosen to cover the entire shoal. A regional correlation based on facies, sequence analysis and outcrop gamma‐ray logs was used as a framework for mapping the distribution of shoal (i. e. reservoir) facies and associated reservoir properties.

Three major depositional environments were recognized: foreshoal, shoal and backshoal. In each environment, specific vertical facies successions composed of thick shallowing‐upward units and thin deepening‐upward units forming metre‐scale cycles were deposited. These small‐scale cycles are stacked and form large‐scale shallowing and deepening trends. Shoal facies developed preferentially in the regressive parts of small‐scale cycles and were found to be laterally continuous over distances of at least several kilometres.

Porous intervals within the shoal facies are concentrated along the tops of the small‐scale shallowing‐upward cycles. The porous intervals in successive small‐scale cycles increase in thickness and in absolute values of porosity upwards through the large‐scale shallowing trend. Separate vug pore types are characterized by relatively low permeabilities (0 to about 10 mD) in spite of the high porosity (up to 20%). The combined occurrence of separate vug and interparticle porosity leads to higher permeabilities (tens of mD).

Isolines of porosity, permeability and net/gross follow the contours of the carbonate shoal complex. The highest values of porosity appear more or less at the centre of the shoal, while the highest values of permeability are found at the shoal margins. The distribution of maximum porosity and maximum permeability zones are thus controlled by the cyclic seaward‐stepping and landward‐stepping of the shoal body.

The systematic variations in extent, stacking pattern and related petrophysical characteristics of the carbonate shoal bodies may be used for modelling shoal reservoirs in producing oilfields.
DETERMINATION OF FAULT SLIP COMPONENTS USING SUBSURFACE STRUCTURAL CONTOURS: METHODS AND EXAMPLES
Authors: Xu S‐S. , Velasquillo‐Martinez L. G. , Grajales‐Nishimura J. M. , Murillo‐Muñetón G. , García‐Hernandez J. , Nieto‐Samaniego A. F.
Published: March 2006

Problems with measuring fault slip in the subsurface can sometimes be overcome by using subsurface structural contour maps constructed from well logs and seismic information. These maps are useful for estimating fault slip since fault motion commonly causes the dislocation of structural contours. The dislocation of a contour is defined here as the distance in the direction of fault strike between two contours which have the same value on both sides of a fault. This dislocation can be estimated for tilted beds and folded beds as follows:

If a dip‐slip fault offsets a tilted bed, the dislocation (Sc) of contours can be estimated from the vertical component (Sv) of the fault slip and the dip (β) of the bedding according to the following relationship: Sc= Sv/tan β. Since Scand β can be measured from a contour map, the vertical component of fault slip can be obtained from this equation.

If a strike‐slip fault offsets a tilted bed, the dislocation (Scs) of contours is equal to the strike‐slip of the fault (Sc), that is, Scs= Ss.

If a fault offsets a symmetric fold, the strike component (Scs) of fault slip and the dislocation of the contours (Sc) can be calculated, respectively, from the equations Scs= (Smax+ Smin) / 2 and Sc= (Smax‐ Smin) / 2. Smaxis the greater total dislocation (Sc+ Scs) of a contour line between the two limbs of the fold and Sminis the smaller total dislocation (Sc‐ Scs) for the same contour line. In this case, Svcan be also calculated using the obtained value of Scand the equation Sv= Sctan β.

Similarly, for an asymmetric fold, the dislocation of contours due to the vertical slip component is Scb= (Smax‐ Smin)/(n + 1), and the strike‐slip component is Ss= Scs= (nSmin+ Smax/(n + 1), where n is the ratio between the values of interlines of the two limbs, and Scbis the dislocation of contours due to the vertical slip component for either of the two limbs (here it is for limb b).

In all cases, three conditions are required for the calculation of contour dislocation:

the contour lines must be approximately perpendicular to the fault strike; the intersection angle between the fault strike and the strike of bedding should be greater than 65°;

the bed must not be dip more than 35°; and

folding or flexure of the stratigraphic horizons must have occurred before faulting.

These methods for determining fault slip from the dislocation of structural contours are discussed using case studies from the Cantarell oilfield complex, Campeche Sound (southern Gulf of Mexico), the Jordan‐Penwell Ellenburger oilfield in Texas, and the Wilmington oilfield in California.
MIDDLE MIOCENE DASHAVA FORMATION SANDSTONES, CARPATHIAN FOREDEEP, UKRAINE
Authors: Kurovets I. , Prytulka G. , Shpot Y. , Peryt T. M.
Published: March 2006

Middle Miocene (Sarmatian) sandstones in the Ukrainian Carpathian Foredeep are important exploration targets for natural gas. In this paper, we report on petrophysical studies on core samples of these sandstones with which we integrate wireline log data from 42 boreholes. Sarmation siltstones and sandstones in the study area are assigned to the lower part of the Dashava Formation. Seventeen units (LD 17 to LD 1:0.05 to 5m thick) are recognized in this formation on the basis of lithostratigraphy and log response. Sandstone content is highest within three lithostratigraphic complexes corresponding to units LD17‐LD14, LD9‐LD8 and LD5‐LD3.

During the Sarmatian, the Carpathian Foredeep was characterized by two depositional systems: a basinal turbidite system, and a second, more mixed system. Important controls on sedimentation included basin configuration and water depth, the occurrence of turbidity and other currents, and the location of provenance areas. Clastic material was delivered to the basin by rivers and ephemeral streams mostly from the Carpathian foldbelt. The content of sandy material within the Sarmatian succession increases from NW to SE, and from the central portion of the Krukenychy depression to the margins of the basin.
THE GENERATION OF IMMATURE OILS IN THE LACUSTRINE JIYANG MEGA‐DEPRESSION, BOHAI BAY BASIN, CHINA
Authors: Linye Zhang , Shouchun Zhang , Zhilin Chen , Chunrong Zhang , Zhihua Hong
Published: March 2006

The lacustrine Jiyang mega‐depression (Bohai Bay Basin, eastern China) produces important volumes of immature oils. These oils were generated at shallow burial depths by source rocks which have not entered the conventional oil window. Oil‐source correlation studies have determined that the oils were mainly generated by source rock intervals in the Es4 and Es1 Members of the Paleogene Shahejie Formation, which were deposited in saline‐ to brackish‐water and brackish‐water lacustrine conditions, respectively. Minor quantities of oil came from Es3 Member source rocks deposited in freshwater conditions.

Samples of the Es4, Es3 and Es1 source rocks underwent artificial maturation at low temperatures (100–400°C). For the Es4 sample, the hydrocarbon generation characteristics of soluble organic matter and kerogen were investigated. The results of the experiments show that soluble organic matter made a greater contribution than kerogen to the immature oil (76% versus 24%). A comparison of the results of the thermal simulation experiments with the naturally‐occurring maturation profile shows that various factors influenced the generation of the immature oils. Firstly, the Es4 and Es1 Members include intervals enriched in algal material. Secondly, most of the immature oil is derived from soluble organic matter. Finally, the saline depositional environment was favorable for the preservation of organic matter.
SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM
Authors: Petersen H. I. , Tru Vu , Nielsen L. H. , Duc Nguyen A. , Nytoft H. P.
Published: March 2006

Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil‐prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock‐Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus‐morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436–572 mg HC/g TOC. From a pyrolysis S2 versus TOC plot it is estimated that about 55% of the mudstones’TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold.

Humic coals and coaly mudstones have Hydrogen Index values of 318–409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial‐derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R0. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential.

The composition of a newly discovered oil (well B10‐STB‐1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half‐grabens in the Song Hong Basin.
A RE‐APPRAISAL OF THE APPLICATION OF ROCK‐EVAL PYROLYSIS TO SOURCE ROCK STUDIES IN THE NIGER DELTA
Authors: Akinlua A. , Ajayi T. R. , Jarvie D. M. , Adeleke B. B.
Published: March 2006

Thirty four shale samples from the Tertiary Agbada Formation were analysed for TOC and Rock‐Eval pyrolysis parameters in order to evaluate the effect of oil‐based mud contamination on source‐rock characterization. The samples were obtained from five wells in the offshore Niger Delta over a depth range of 5,460ft to 11,580ft. The results indicated that the raw (unextracted) samples were dominated by Type III kerogen. However, after extraction, both Types II/III and III kerogen were identified, consistent with previous studies. These results demonstrate that it is essential that shale samples should be extracted prior to TOC and Rock‐Eval pyrolysis for accurate source‐rock evaluation.
TURBIDITE, SLUMP AND DEBRIS FLOW DEPOSITS AT THE KALCHINSKOE AND ZIMNEE OILFIELDS, WEST SIBERIAN BASIN
Authors: Khafizov S. F. , Syngaevsky P. E.
Published: March 2006

This paper discusses specific facies associated with Cretaceous deep‐water slumps and sandstone intrusions in the West Siberian Basin. The slumps were formed during sea‐level falls when storms caused sediment masses to be discharged into deep‐water areas where they imposed a significant load on the underlying semi‐consolidated black shales, deforming and partially destroying them. Multiple slump / avalanche events are observed at the boundary between the Lower Cretaceous (Neocomian) and Upper Jurassic (Tithonian) sequences and form potential targets for oil exploration.

High‐resolution sequence stratigraphic analyses show that both slump and distal fans are genetically related to lower slope/basin floor sediments and were deposited during regressions and subsequent lowstands. Two key depositional environments are recognized: the proximal parts of fans, where the most prospective potential reservoirs are found; and the more distal parts of slumps, which are principally composed of deformed shale clasts in a silt‐mudstone matrix. A third facies (“slump head”) is only observed on seismic profiles and is probably related to horizontally displaced “shingled” semi‐consolidated black shales.
HYDROCARBON GENERATION HABITAT OF TWO CRETACEOUS CARBONATE SOURCE ROCKS IN SE TURKEY
Authors: Soylu C. , Yalçin M. N. , Horsfield B. , Schenk H. J. , Mann U.
Published: March 2006

A detailed petroleum geochemical study has been carried out on two Cretaceous carbonate source rock units, the Karababa Formation A Member and the Karabogaz Formation, in the Adiyaman area of SE Turkey. The purpose was to compare the hydrocarbon generation habitat of these two units which appear to be almost identical in terms of their bulk source rock characteristics. Thus, the TOC contents of the Karababa Formation A Member and the Karabogaz Formation are 0.24–3.79% and 0.50–5.86%, respectively. Hydrogen Indices are generally greater than 300 mg HC/ g TOC and both units have similar maturity levels. However, the results of pyrolysis‐gas chromatographic analyses showed that the organic matter in the Karababa Formation A Member is richer in sulphur compounds, and the presence of sulphur‐rich kerogen resulted in the early generation of hydrocarbons from this unit. Both the dominant activation energy and the frequency factor turned out to be lower for the Karababa Formation A Member. Consequently, oil generation in the Karababa Formation A Member proceeds more rapidly for a given temperature history than it does in the Karabogaz Formation. Moreover, the results of multi‐step Py‐GC analyses indicated that the composition of hydrocarbons generated in these two carbonate source rocks will be different, particularly during the early stages of maturation. Early‐generated oil from the Karababa Formation A Member has the composition of a mature oil, whereas oil from the Karabogaz Formation reaches the same composition at a higher maturity.
DEEP SEISMIC REFLECTION DATA FROM OFFSHORE WESTERN GREECE: A NEW CRUSTAL MODEL FOR THE IONIAN SEA
Authors: Kokinou E. , Kamberis E. , Vafidis A. , Monopolis D. , Ananiadis G. , Zelilidis A.
Published: March 2006

Contractional structures recognised in a recent SW‐NE oriented seismic profile offshore western Greece, between the islands of Zakynthos and Kefallinia (Cephalonia), indicate that this part of the Pre‐Apulian geotectonic zone was involved in Quaternary shortening related to the westward propagation of the Hellenic fold‐and‐thrust system. Deep reflector horizons including the Moho and the top of the crystalline basement were identified on the profile. Shallower reflectors include those corresponding to the contacts between the Mesozoic/Miocene, Upper Miocene/Lower Pliocene, and Pliocene/Pleistocene sedimentary sequences. The Upper Cenozoic to Quaternary sequence rests unconformably upon Mesozoic carbonates. Triassic evaporites wedge‐out in the Paxos geotectonic zone, where the Palaeozoic passes up into Mesozoic deposits.

We have identified contractional structures which were reactivated during the Plio‐Quaternary on pre‐existing high‐angle normal faults, and which gave rise to significant topographic anomalies. West‐dipping normal faults were also recognised both within the Palaeozoic and Cenozoic successions, and are related to regional extension during sedimentation. East‐dipping thrust faults which root in the evaporites were also identified on the seismic profile.

Due to right‐lateral strike‐slip activity on the Kefallinia Transform Fault, east‐dipping normal faults were formed within the lonion abyssal plain. This abyssal plain together with the Hellenic Trench, an accretionary prism, and a forearc basin can be recognised on the seismic profile. A “triple junction” between the Apulian (African) Platform, the oceanic crust of the Ionian Abyssal Plain and the Eurasian Plate in the west of the line is related to the Kefallinia Transform Fault. Neotectonic structural deformation (i.e. Quaternary‐Holocene) is superimposed on the above‐mentioned structures. Finally, diapiric movement of Triassic evaporites has affected both the Alpine and the late Cenozoic to Holocene sedimentary sequences. Diapiric activity continues at the present day in the eastern part of the profile, in the lonian geotectonic zone. The forearc basin may be prospective for hydrocarbons. Target areas include the lonian channel where a play has already been located, and its extension to the south (the Kyparisiakos Gulf area). Here, thick late Cenozoic to Quaternary deposits may act as a top‐seal above a reservoir consisting of eroded Mesozoic to Eocene carbonates, as at the recent Katakolon discovery.
FLOODPLAIN DEPOSITS AND SOIL CLASSIFICATION: THE PREDICTION OF CHANNEL SAND DISTRIBUTION WITHIN THE TRIASSIC ARGILOGRESEUX INFERIEUR, BERKINE BASIN, ALGERIA
Authors: Sabaou N. , Lawton D. E. , Turner P. , Pilling D.
Published: March 2006

Middle to Late Triassic fluvio‐lacustrine sandstones referred to as the Trias Argilo‐Grèseux Inférieur (TAG‐I) are an important hydrocarbon reservoir in the Algerian Berkine Basin. Three depositional sequences have been identified within the TAG‐I and a fourth sequence overlies it, forming part of the “Trias Argilo‐Carbonaté”. Subtle changes in the style of sedimentation through these sequences have been identified and are attributed to periodic rises in base‐level together with changes in subsidence rate and climate, leading to basinward, progradational shifts of the fluvial systems. The palaeoclimate changed from semi‐arid to sub‐humid with seasonal wetting and drying, as indicated by the evolved style of the deposition, the abundance of vegetation and the nature of associated palaeosols. Four main types of palaeosol profile have been identified and consist of green/grey, red, and red/brown to purple palaeosols together with green/grey to red pedogenically modified mudstones, depending on the level of maturity.

The presence of sphaerosiderites in green palaeosols is a clear indication of the occurrence of wetland conditions. Palaeosol development and maturity are useful aids to stratigraphic correlation and as an indication of the proximity of reservoir channel sandstones. With improved prediction of the sandbodies’location, better models of reservoir distribution can be made leading to an enhanced field development plan