Showing papers in "Journal of Petroleum Geology in 2005"

The influence of tectonics on the entrapment of oil in the dezful embayment, zagros foldbelt, iran

Abstract: The timing of the orogenic events associated with the closure of South Tethys significantly influenced the generation, migration and entrapment of petroleum in the Zagros Foldbelt of Iran. This influence was particularly important in the Dezful Embayment, which is one of the world's richest oil provinces, containing some 8% of global oil reserves in an area of only 60,000 sq. km. In the Dezful Embayment, oil and associated gas occur in two carbonate reservoirs - the Sarvak Formation of Cenomanian to Turonian age, and the Oligocene - Early Miocene Asmari Formation, sealed by the evaporites of the Gachsaran Formation. The oil and associated gas are trapped in large “whaleback” anticlines which formed during the Neogene Zagros orogeny. Two excellent source rocks, the Albian Kazhdumi Formation and the upper part of the Pabdeh Formation (Middle Eocene to Early Oligocene), supplied the Asmari and Sarvak reservoirs and with them form the Middle Cretaceous to Early Miocene Petroleum System. This system was found to be independent of older petroleum systems. Two particular problems are addressed in this paper. The first is the relative timing of trap formation versus oil expulsion from the source rocks. If oil expulsion occurred prior to Zagros folding, the oil would have migrated along gently dipping ramps towards the Persian (Arabian) Gulf and Southern Iraq, and would have been trapped a long way from the source kitchen. By contrast, if oil expulsion took place when the whaleback anticlines already existed or had at least begun to develop, the oil generated would have moved almost vertically towards the nearest anticline. Secondly, we assess the type of heatflow to be used for modelling. This could be either variable or constant, depending on the stability or instability of the Arabian Platform and on subsidence variations during source rock maturation. Our conclusions can be summarized as follows. First, the paroxysmal phase of Zagros folding commenced in the Dezful Embayment towards the end of the Middle Miocene around 10 Ma ago and continued throughout the Late Miocene and Pliocene. Second, bearing in mind the remarkable stability of the Arabian Platform for some 260 Ma, during which there was almost continuous gentle subsidence between the Permian transgression and the Early Miocene, a constant heatflow was used for modelling. Burial profiles and maturity indices, such as vitrinite reflectance and Rock-Eval parameters, demonstrate that the Kazhdumi and Pabdeh source rocks reached the onset of oil expulsion during deposition of the Agha Jari Formation between 8 and 3Ma, depending upon the location. This chronology means that oil migrated from source rocks into preexisting Zagros structures. Therefore, oil migrated over short distances to nearby traps within well-defined drainage areas, the geometry of which can be deduced from seismic data. Moreover, the Zagros folding induced prominent fracturing which can be observed both at outcrop and in wells. This fracturing, which affects lime-stones as well as marls, enhanced subvertical migration of hydrocarbons towards the reservoirs. As a result of this short distance migration, oils can directly be linked to the source rocks which generated them by oil-oil and oil-source rock correlations based on stable isotope (σ13C, σ34S) and biomarker data. Modelling of each drainage area provides estimates of the amount of oil expelled by each source rock. Calculated estimates can then be compared to the actual oil-in-place of the corresponding field. An example of this modeling procedure is given in this paper.

Deep seismic reflection data from offshore western greece: a new crustal model for the ionian sea

Abstract: 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.

Source Rock Properties of Lacustrine Mudstones and Coals (oligocene Dong HO Formation), Onshore Song Hong Basin, Northern Vietnam

Abstract: 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 S 2 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%R o . 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.

Source rock evaluation and petroleum geochemistry, offshore sw iran

Abstract: Mesozoic and Tertiary source rocks and crude oils from six oilfields in the Persian (Arabian) Gulf (Hendijan, Bahrgansar, Abouzar, Nowruz, Dorood and Foroozan) were studied using a variety of organic-geochemical techniques. Biomarker characteristics were combined with other geochemical data to identify the source rocks which generated the oil in these fields and to reconstruct their depositional environments, and also to characterize the diagenetic and catagenic processes which have occurred. The analyzed oils show a wide range of densities (19 to 39° API) and high sulphur contents. They were generated by Type II-S organic matter; they are not biodegraded and their maturity level is generally low. Two main oil groups were identified from statistical analysis and can be correlated with different source rocks using age-specific biomarkers and isotope data. Group 1 oils include those from the Hendijan, Bahrgansar and Abouzar fields and were probably generated by a mid-Cretaceous argillaceous source rock. Group 2 oils include those from the Nowruz, Dorood and Foroozan fields, and originated from Jurassic to Early Cretaceous carbonate-rich source rocks.

Origin and reservoir rock characteristics of dolostones in the early triassic feixianguan formation, ne sichuan basin, china: significance for future gas exploration

Abstract: Major discoveries of natural gas have recently been made in the oolitic dolostones of the Early Triassic Feixianguan Formation in NE Sichuan Province, Southern China. These dolostones were formed by three facies-controlled dolomitization processes: (i) meteoric mixing zone dolomitization with dolomites having a relatively high degree of crystalline order (δ13C:−1.0 to 2.5%PDB; δ18O:−6.5 to −2.5%PDB); (ii) seepage-reflux dolomitization associated with evaporative brines; the corresponding dolomite crystals are relatively ordered and were formed in tidal flat environments and platform-margin oolitic shoals adjacent to lagoons; (iii) burial dolomitization (shallow to moderate burial depths, ca. 1,000 to 4,000m), whereby seawater-derived brines were present in the host rock and the resultant water/rock reactions played a major role in dolomitization. The three dolomitization processes were controlled by the arid climate prevailing during the Early Triassic, and also by fourth-order relative sea-level changes, especially with respect to the reflux dolomitization. Burial dolomitization, which is of second-order of importance for porosity development, was strongly dependant on the presence of sufficient original porosity to facilitate water-rock reactions within the carbonates. The best reservoir rocks formed as oolitic banks and bars in the vicinity of evaporative lagoonal-tidal complexes which experienced optimal conditions for dolomitization. Dolostones with a dolomite content of 80% to 90% form good vuggy reservoir rocks at the present day, indicating that the intensity of dolomitization influences the quality of reservoir rocks. According to our results, future gas exploration in the Feixianguan Formation dolostone reservoirs should focus on locating oolitic banks associated with evaporative lagoon and tidal flat complexes and delineating the best structural/lithological traps.

Hydrocarbon seepage and carbonate mound formation: a basin modelling study from the porcupine basin (offshore ireland)

Abstract: This study assesses whether the growth of deep water carbonate mounds on the continental slope of the north Atlantic may be associated with active hydrocarbon leakage. The carbonate mounds studied occur in two distinct areas of the Porcupine Basin, 200 km offshore Ireland, known as the Hovland-Magellan and the Belgica areas. To evaluate the possible link between hydrocarbon leakage and mound growth, we used two dimensional cross-section and map-based basin modelling. Geological information was derived from interpretation of five seismic lines across the province as well as the Connemara oilfield. Calibration data was available from the northern part of the study area and included vitrinite reflectance, temperature and apatite fission track data. Modelling results indicate that the main Jurassic source rocks are mature to overmature for hydrocarbon generation throughout the basin. Hydrocarbon generation and migration started in the Late Cretaceous. Based on our stratigraphic and lithologic model definitions, hydrocarbon migration is modelled to be mainly vertical, with only Aptian and Tertiary deltaic strata directing hydrocarbon flow laterally out of the basin. Gas chimneys observed in the Connemara field were reproduced using flow modelling and are related to leakage at the apices of rotated Jurassic fault blocks. The model predicts significant focussing of gas migration towards the Belgica mounds, where Cretaceous and Tertiary carrier layers pinch out. In the Hovland-Magellan area, no obvious focus of hydrocarbon flow was modelled from the 2D section, but drainage area analysis of Tertiary maps indicates a link between mound position and shallow Tertiary closures which may focus hydrocarbon flow towards the mounds.

Indications for an active petroleum system in the laptev sea, ne siberia

Abstract: The shallow shelf of the Laptev Sea offshore NE Siberia is characterized by a number of rift basins more than 10 km deep. These basins are filled with sedimentary rocks of predominantly Cenozoic age and are likely sites for petroleum generation and accumulation. One objective of the BGR97 Arctic cruise to the Laptev Sea was to explore for near-surface indications of petroleum, and for this purpose water samples and near-surface sediments were collected for geochemical analysis. Gaseous hydrocarbons adsorbed in near-surface sediments include thermally-generated gas which has probably migrated upwards from deeper sedimentary strata. The hydrocarbons’compositions together with stable carbon isotope ratios indicate an origin from a marine source rock at a maturity of between 0.9 and 1.3% vitrinite reflectance. On reflection seismic profiles, zones of poor reflectivity were observed locally, also suggesting the presence of ascending gas. These geophysical indications for gas occur most frequently in the northern part of the Laptev Sea; here, seepages of thermogenic methane were detected in the sea water at two locations. Refraction seismic and multichannel data indicate the existence of sub-sea permafrost down to a depth of 500m, which probably prevents gas from escaping into the water column in most areas. The greater water depths at the northern edge of the shelf may have prevented the formation of the permafrost layer, allowing the upward migration of hydrocarbons to occur.

A re‐appraisal of the application of rock‐eval pyrolysis to source rock studies in the niger delta

Abstract: 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.

Source rock characterization based on biological marker distributions of crude oils in the southern gulf of suez, egypt

Abstract: The depositional environment and maturity of source rocks in the southern Gulf of Suez were evaluated using biomarker and isotope data from crude oils derived from a variety of source rock types of different geological ages. Two oils families were identified and are referred to as types A and B. Type A oils are characterized by a predominance of oleanane and relatively low gammacerane concentrations, suggesting that they were derived from a terrigenous source rock with a significant input of angiosperm material inferred to occur within the marginally-mature syn-rift Lower Miocene Rudeis Shale. By contrast, type B oils are distinguished by a predominance of gammacerane and relatively low oleanane concentrations, suggesting that they were generated from mature marine carbonate source rocks inferred to occur within the Upper Cretaceous Brown Limestone and Middle Eocene Thebes Formation. Maturity parameters including the sterane isomerisation ratios C29αββ/(αββ+ααα), C29ααα20S/(S+R) and TAS/(TAS+MAS), together with aromatic sulphur compound ratios (4-MDBT / I-MDBT; 4,6- / 1,4-DMDBT; 2,4–/ 1,4-DMDBT; and DBT / phenanthrenes), support the higher thermal maturity of type B oils relative to type A oils. The biomarker variablility reflects the occurrence of two distinct source rocks in the southern Gulf of Suez and suggests that two independent petroleum systems are present here. These appear to be confined to the pre-rift (pre-Miocene) and syn-rift megasequences respectively.

Distribution of source rocks and maturity modelling in the northern cenozoic song hong basin (gulf of tonkin), vietnam

Abstract: The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub-commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone. Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break-down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yukler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R0 algorithm. Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yukler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion. Lacustrine mudstones, similar to the highly oil-prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW–SE Paleogene half-grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale-prone seismic facies and the modelled extent of the present-day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO-STB-IX) at the margin of the basin, which is sourced mainly from “Dong Ho type” lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system.

Evaluation of the controls on fracturing in reservoir rocks

Abstract: The style, geometry and distribution of fractures within reservoir rocks can be controlled by numerous factors, including: rock characteristics and diagenesis (lithology, sedimentary structures, bed thickness, mechanical stratigraphy, the mechanics of bedding planes); structural geology (tectonic setting, palaeostresses, subsidence and uplift history, proximity to faults, position in a fold, timing of structural events, mineralisation, the angle between bedding and fractures); and present-day factors, such as orientations of in situ stresses, fluid pressure, perturbation of in situ stresses and depth. The relative timing of events plays a crucial role in determining the geometry and distribution of fractures. For example, open fractures are commonly clustered around faults if the open fractures and faults formed at the same time, but clustering does not tend to occur if the open fractures pre-date or post-date the faults. Understanding these factors requires traditional geological skills, including the analysis of one-dimensional (line-sampling) data from core, borehole images and exposed analogues. This paper reviews the factors that control fractures within reservoir rocks and discusses methods to assess those controls. Examples are presented from Mesozoic limestones in southern England. It is shown that traditional geological skills are of vital importance in determining the rock characteristics, structural and present-day factors that control fractures.

Late to middle jurassic source facies and quality variations, south viking graben, north sea

Abstract: Source facies and quality of the Late to Middle Jurassic source rock system in the South Viking Graben between 58°N and 60°15'N are highly variable both regionally and stratigraphically. In order to assess the degree of variability and to create a model of source rock quality and potential, isochore maps of the syn- and post-rift sections of the Upper Jurassic Draupne Formation and underlying Heather Formation were generated from seismic and well data, and maturity-corrected Rock-Eval data were used to generate quantitative maps of oil and gas potential. The thin post-rift section at the top of the Draupne Formation is a rich oil-prone source, while the up to 1,600 m thick syn-rift section contains a mixture of Type III and Type II material with substantial amounts of gas-prone and inert organic matter. The Heather Formation, which reaches modelled thicknesses of up to 930 m, is a lean source and is generally gas-prone. Detailed analyses and interpretations of biomarker and isotopic characteristics support this upward increase in oil-prone Type II material. The analytical parameters include increasing relative amounts of C27 regular steranes; decreasing ratios of C30 moretane relative to C30 hopane; and an increasing predominance of short chain n-alkanes and progressively lighter isotopic values for saturate and aromatic fractions of source rock extracts. In addition, increasing amounts of 17α(H),21β(H)-28,30-bisnorhopane and decreasing amounts of C34 homohopanes relative to C35 homohopanes, as well as decreasing Pr/Ph ratios, suggest a general decrease in oxygenation upwards. Maps of average Pr/Ph ratios for the syn- and post-rift Draupne Formation and for the Heather Formation are consistent with permanent water column stratification and gradual ascent of the O2:H2S interface from the Callovian to the Ryazanian. Interpretation of oil and gas potential maps, molecular parameters and estimates of sediment accumulation rates in combination suggest that the source facies of the upper, post-rift Draupne Formation is controlled by widespread anoxia, reduced siliciclastic dilution and reduced input of gas-prone organic and inert material; by contrast, the potential of the lower, syn-rift Draupne Formation is strongly controlled by dilution by gas-prone and inert organic matter resulting from mass flows and also by varying degrees of oxygenation. The oil and gas potential of the Heather Formation is mainly controlled by the degree of oxygenation and siliciclastic dilution.

The structural style of sedimentary basins on the shelves of the laptev sea and western east siberian sea, siberian arctic

Abstract: A total of 11,700 km of multichannel seismic reflection data were acquired during three recent reconnaissance surveys of the wide, shallow shelves of the Laptev and western East Siberian Seas in the Siberian Arctic Ocean. Three seismic marker horizons were defined and mapped in both shelf areas. Their nature and age were predicted on the basis of regional tectonic and palaeoenvironmental events and corroborated using onshore geology. To the north of the Laptev Sea, the Gakkel Ridge, an active mid-ocean ridge which separates the North American and Eurasian Plates, abruptly meets the steep slope of the continental shelf which is curvilinear in plan view. Extension has affected the Laptev Shelf since at least the Early Tertiary and has resulted in the formation of three major, generally north-south trending rift basins: the Ust’Lena Rift, the Anisin Basin and the New Siberian Basin. The Ust’Lena Rift has a minimum east-west width of 300km at latitude 75°N and a Cenozoic infill up to 6 s (twt) in thickness. Further to the NW of the Laptev Shelf, the downthrown and faulted basement is overlain by a sub-parallel layered sedimentary succession with a thickness of 4 s (twt) that thins towards the west. Although this area was affected by extension as shown by the presence of numerous faults, it is not clear whether this depression on the NW Laptev Shelf is continuous with the Ust’Lena Rift. The Anisin Basin is located in the northern part of the Laptev Shelf and has a Cenozoic sedimentary fill up to 5 s (twt) thick. The deepest part of the basin trends north-south. To the west is a secondary, NW-SE trending depression which is slightly shallower than the main depocentre. The overall structure of the basin is a half-graben with the major bounding fault in the east. The New Siberian Basin is up to 70 km wide and has a minimum NW-SE extent of 300 km. The sedimentary fill is up to 4.5 s (twt) thick. Structurally, the basin is a half-graben with the bounding fault in the east. Our data indicate that the rift basins on the Laptev Shelf are not continuous with those on the East Siberian Shelf. The latter shelf can best be described as an epicontinental platform which has undergone continuous subsidence since the Late Cretaceous. The greatest subsidence occurred in the NE, as manifested by a major depocentre filled with inferred (?)Late Cretaceous to Tertiary sediments up to 5 s (twt) thick.

Characterisation of epeiric “layer‐cake” carbonate reservoirs: upper muschelkalk (middle triassic), the netherlands

Abstract: Upper Muschelkalk (Middle Triassic) carbonates produce natural gas at Coevorden field in the NE Netherlands. This is currently the only field which produces gas from this succession although several other prospects have been identified nearby. In order to help develop these hydrocarbons, this study proposes a facies and reservoir model of the Upper Muschelkalk in the NE Netherlands together with a regional framework intended to assist in further evaluation. Distribution of facies and reservoir properties of the Upper Muschelkalk carbonates in the NE Netherlands indicate deposition on a storm-dominated epeiric ramp with a very low gradient. The predominantly muddy and marly lithofacies types in proximal and distal parts of the ramp gradually interfinger with a shoreline-detached “shoal”-like ooidal grainstone complex. The best reservoir quality (permeability up to 60 mD) is recognised within dolomitised peloid ooid grainstones. These are interpreted as high-energy backshoal deposits. Reservoir quality decreases in the limestone-dominated “shoal” facies and the muddier foreshoal facies. A four-fold hierarchy of depositional cycles describes the systematic and thus predictable vertical variation in reservoir quality (permeability) and quantity (net-to-gross). High-resolution correlation suggests that medium-scale cycles (5 to 15 metres thick) can be traced for hundreds of kilometres. Small-scale cycles (1 to 3 metres thick) are persistent for several tens of kilometres and have sheet-like geometries. Individual reservoir units (several decimetres thick) appear to be laterally continuous over a maximum of a few kilometres although internal flow barriers might be expected. Mapping of Upper Muschelkalk thickness and facies has clearly defined backshoal, ”shoal and foreshoal facies belts with distinctly different reservoir characteristics. Typically, reservoir quality and quantity decrease with increasing thickness of the Upper Muschelkalk and the underlying Middle Muschelkalk halite. The systematic variations in thickness are apparently controlled by a combination of palaeogeography and palaeotectonics. The best reservoir quality and highest quantity is found on a palaeohigh characterised by a relatively thin Upper Muschelkalk succession and the absence of underlying halite. These features can also be recognised in seismic data. The results of this case study can also be applied in the integrated characterisation of similar epeiric carbonates constituting highly productive reservoirs in the Middle East, including the Khuff and Arab Formations.

Geochemical correlation of oils and source rocks from central and ne syria

Abstract: Eighteen crude oils and seven source rock samples from the Mesopotamian foredeep, NE Syria, and from the NE Palmyrides in the centre of the country have been characterized by geochemical techniques. The presence of two oil families (“A” and “B”) generated by different source rock types of different ages has been established on the basis of biomarker and carbon isotopic analyses. The data indicates that Groups A and B oils were generated by marine clastic and marine carbonate-evaporitic source rocks, respectively. Group A oils, occurring in Middle Triassic, Middle Jurassic and Upper Cretaceous reservoir rocks in the NE Palmyride area, are geochemically similar to extracts from the Lower Triassic Amanus Shale Formation. Group B oils, which are present in Middle Triassic, Middle Jurassic and Upper Cretaceous reservoirs in the Mesopotamian foredeep, are geochemically similar to extracts of the Middle Triassic Kurra Chine Dolomite and Upper Cretaceous Shiranish Formations.

The lacustrine liangjialou fan in the dongying depression, eastern china: deep-water reservoir sandstones in a non-marine rift basin

Abstract: A lacustrine fan covering an area of about 175sq. km has been identified in the Liangjialou area in the SW of the Dongying Depression, a Tertiary non-marine rift basin in eastern China. Fluvial and deltaic sandstones are established reservoir rocks in the basin, and the deep-water sandstones of the fan succession, which are assigned to Member 3 of the lower Tertiary Shahejie Formation, are also thought to have important reservoir potential. Available data for this study included some 800m of core from 16 wells, well-log data from 426 wells, and 220 sq.km of 3D surveys together with well-test and other production data. From geomorphological reconstructions of the fan, we distinguish first-order (major) fan channels from second-order branched and more distal tip channels. Crevasse splays and overbank shales occur between channels, and sandstone lobes were deposited at channel mouths. Conglomeratic sandstones deposited in major channels are probably the most promising reservoir facies (average porosity c. 20%; average permeability > 1D). Fan construction took place during a single complete cycle of lake level variation which was composed of several sub-cycles. During initial highstand conditions, the fan was dominated by small-scale branched and tip channels and intervening sandy lobes. Fan size increased rapidly during the following lowstand, and then decreased during the ensuing highstand.

Geochemical characteristics of oil seepages from dam thi nai, central vietnam: implications for hydrocarbon exploration in the offshore phu khanh basin

Abstract: Dam Thi Nai is a semi-enclosed embayment on the coast of central Vietnam, adjacent to the northern part of the offshore and largely unexplored Phu Khanh Basin. Seepages of oil have been known in Dam Thi Nai since the early part of the twentieth century. This paper presents organic geochemical data on a number of samples of seepage oil collected from Dam Thi Nai and discusses their implications for the prospectivity of the Phu Khanh Basin. The results indicate that the petroleum was generated from a Tertiary marine marl source rock. Seepage oils are found in varying degrees of biodegradation and modes of occurrence at different locations in the embayment. Thus, oil was observed to fill fractures in freshly quarried outcrops of Cretaceous granite, and also occurs in shallow pits dug in the beach sand and in shallow basins used for shrimp farming. The oils indicate active seepage from kitchen areas or leaking accumulations in the Phu Khanh Basin. Seismic data suggest the existence of both source rocks and kitchens, and indicate a possible migration route from the deep basin to the surface at the bay. A few samples show anomalous compositions, indicating the presence of two other oil types which have different sources. These occurrences cannot at present be explained. However, the results obtained are encouraging for future exploration in the Phu Khanh Basin.

Floodplain deposits and soil classification: the prediction of channel sand distribution within the triassic argilogreseux inferieur, berkine basin, algeria

Abstract: Middle to Late Triassic fluvio-lacustrine sandstones referred to as the Trias Argilo-Greseux Inferieur (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-Carbonate”. 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

Hydrocarbon generation habitat of two cretaceous carbonate source rocks in se turkey

Abstract: 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.

A review of geological data that conflict with the paradigm of catagenic generation and migration of oil

Abstract: The majority of petroleum geologists today agree that the complex problems that surround the origin, generation, migration and accumulation of hydrocarbons can be resolved by accepting the geochemical conclusion that the process originates by catagenic generation in deeply-buried organically-rich source rocks. These limited source rock intervals are believed to expel hydrocarbons when they reach organic maturity in oil kitchens. The expelled oil and gas then follow migration pathways to traps at shallower levels. However, there are major geological obstacles that cast doubt upon this interpretation. The restriction of the source rock to a few organically rich levels in a basin forces the conclusion that the basin plumbing system is leaky and allows secondary horizontal and vertical migration through great thicknesses of consolidated sedimentary rocks in which there are numerous permeability barriers that are known to effectively prevent hydrocarbon escape from traps. The sourcing of lenticular traps points to the enclosing impermeable envelope as the logical origin of the trapped hydrocarbons. The lynch-pin of the catagenic theory of hydrocarbon origin is the expulsion mechanism from deeply-buried consolidated source rock under high confining pressures. This mechanism is not understood and is termed an “enigma”. Assuming that expulsion does occur, the pathways taken by the hydrocarbons to waiting traps can be ascertained by computer modelling of the basin. However, subsurface and field geological support for purported migration pathways has yet to be provided. Many oilfield studies have shown that oil and gas are preferentially trapped in synchronous highs that were formed during, or very shortly after, the deposition of the charged reservoir. An unresolved problem is how catagenically generated hydrocarbons, expelled during a long-drawn-out maturation period, can have filled synchronous highs but have avoided later traps along the assumed migration pathways. From many oilfield studies, it has also been shown that the presence of hydrocarbons inhibits diagenesis and compaction of the reservoir rock. This “Fuchtbauer effect” points to not only the early charging of clastic and carbonate reservoirs, but also to the development of permeability barriers below the early-formed accumulations. These barriers would prevent later hydrocarbon additions during the supposed extended period of expulsion from an oil kitchen. Early-formed traps that have been sealed diagenetically will retain their charge even if the trap is opened by later structural tilting. Diagenetic traps have been discovered in clastic and carbonate provinces but their recognition as viable exploration targets is discouraged by present-day assumptions of late hydrocarbon generation and a leaky basin plumbing system. Because there are so many geological realities that cast doubt upon the assumptions that devolve from the paradigm of catagenic generation, the alternative concept of early biogenic generation and accumulation of immature oil, with in-reservoir cracking during burial, is again worthy of serious consideration. This concept envisages hydrocarbon generation by bacterial activity in many anoxic environments and the charging of synchronous highs from adjacent sources. The resolution of the fundamental problem of hydrocarbon generation and accumulation, which is critical to exploration strategies, should be sought in the light of a thorough knowledge of the geologic factors involved, rather than by computer modelling which may be guided by questionable geochemical assumptions.

A method for analyzing geothermal gradient histories using the statistical assessment of uncertainties in maturity models

Abstract: A major factor contributing to uncertainty in basin modelling is the determination of the parameters necessary to reconstruct the basin's thermal history. Thermal maturity modelling is widely used in basin modelling for assessing the exploration risk. Of the available models, the chemical kinetic model Easy%Ro has gained wide acceptance. In this study, the thermal gradient at five wells in the Danish North Sea is calibrated against vitrinite reflectance using the Easy%Ro model coupled with an inverse scheme in order to perform sensitivity analysis and to assess the uncertainty. The mean squared residual (MSR) is used as a quantitative measure of mismatch between the modelled and measured reflectance values. A 90% confidence interval is constructed for the determined mean of the squared residuals to assess the uncertainty for the given level of confidence. The sensitivity of the Easy%Ro model to variations in the thermal gradient is investigated using the uncertainty associated with scatter in the calibration data. The best thermal gradient (minimum MSR) is obtained from the MSR curve for each well. The aim is to show how the reconstruction of the thermal gradient is related to the control data and the applied model. The applied method helps not only to determine the average thermal gradient history of a basin, but also helps to investigate the quality of the calibration data and provides a quick assessment of the uncertainty and sensitivity of any parameter in a forward deterministic model.

Hydrocarbon source rocks and generation history in the Lunnan oilfield area, northern Tarim Basin (NW China)

Abstract: In this paper we report on source rocks and maturation history at the Lunnan oilfield, northern Tarim Basin (NW China), using a combination of organic petrographic and geochemical techniques. Three separate source rock intervals are present here: Cambrian mudstones and argillaceous limestones; Middle and Upper Ordovician argillaceous limestones; and Triassic mudstones. Reservoir rocks comprise Lower Ordovician carbonates, Carboniferous sandstones, and Triassic and Jurassic sandstones. Structural traps were formed principally during the Silurian and Jurassic. The Lunnan field is located on a small-scale palaeo uplift which developed during the Early Palaeozoic. Hydrocarbons migrated updip from source areas in surrounding palaeo-lows along faults and unconformities. Major phases of hydrocarbon generation and migration occurred in the Early Silurian – Late Devonian, Cretaceous – Early Tertiary and Late Tertiary. Uplift and intense erosion at the end of the Devonian destroyed Early Palaeozoic oil and gas accumulations sourced from the Cambrian source rocks, but hydrocarbons generated by Middle and Upper Ordovician source rocks during the Mesozoic and Tertiary have been preserved. At the present day, accumulations are characterized by a range of crude oil compositions because source rocks from different source areas with different maturation histories are involved.

Turbidite, slump and debris flow deposits at the kalchinskoe and zimnee oilfields, west siberian basin

Abstract: 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.