Journal of Petroleum Geology最新文献

The Mid North Sea High (MNSH) region represents one of the least explored areas for the Late Permian Zechstein Hauptdolomit play in the Southern Permian Basin although some of the first offshore wells drilled in the UK were located here. In other parts of the basin such as onshore Poland, the Hauptdolomit Formation (“Hauptdolomit”) is an active and attractive exploration target, with oil and gas production from commercial-sized fields. In the UK, the play has been overshadowed by drilling campaigns in areas to the south of the MNSH which tested plays in the underlying Rotliegend and Carboniferous successions. However, with these areas now in decline, there is increased exploration interest in the Hauptdolomit in the MNSH region, particularly since 2019 when 3D seismic data were acquired and the first hydrocarbon discovery was made at Ossian (well 42/04-01/1Z). Geochemical data from the latter discovery have pointed to the presence of a prolific petroleum system with the potential for Hauptdolomit reservoirs to be charged both by Zechstein-generated oils and Carboniferous condensate/gas. With regard to hydrocarbon migration and preservation in the southern MNSH, a detailed evaluation of the effects of the Mid Miocene Unconformity has allowed for a greater understanding of the main factors controlling hydrocarbon preservation and remigration. Reservoir characterization of the Hauptdolomit play has been achieved by integrating petrographic microfacies analyses, core data and petrophysical interpretations. The most important factors controlling reservoir quality are the presence and extent of anhydrite cementation and the presence of high energy shoal facies. Thicker and coarser grained shoal facies are expected to occur along the yet-to-be explored Orchard platform margin where numerous prospects have been mapped and refined using recently acquired 3D seismic data.

A multidisciplinary approach combining geological mapping based on seismic and well data with petrographic analyses of core and cuttings samples was used to gain a better understanding of the distribution of Upper Permian (Zechstein, Z2) Hauptdolomit platforms and their depositional facies around the Elbow Spit High in the northern Dutch offshore. A detailed understanding of the Hauptdolomit's lateral facies variability is of great importance for assessing its reservoir potential, since both the thickness and reservoir properties of these carbonate platforms greatly depend on local accommodation within different palaeo-depositional environments. The platforms generally contain the thickest Hauptdolomit sequences and are largely characterised by a mix of oolitic and coated grainstones, as well as by some dolomicrites. Porosities of around 15% are reached at well E02-02 within the grainstone intervals, and interconnectivity between the pores is generally present. Seismic mapping has indicated a rim of isolated Hauptdolomit platforms, which are up to 10 km wide, around the southern and NW margins of the Elbow Spit High. No Hauptdolomit platforms are present on the NE margin of the High, likely because the palaeo- basin margin was too steep and hence lacked accommodation for carbonate growth. Discoveries made in recent years in the UK sector of the southern North Sea have highlighted the importance of the Hauptdolomit hydrocarbon play, and the results of the current study provide a solid base for assessing the reservoir potential of this play in the relatively underexplored northern part of the Dutch offshore.

The Upper Permian Zechstein Supergroup has the potential to play an important role in the UK's future energy production and energy transition. However the Supergroup is comparatively poorly understood in the UK, particularly the link between the onshore and offshore geology. In this paper we re-evaluate available data in order to present a consistent regional interpretation of the Z1 to Z3 Zechstein Supergroup cycles. This review is based on an interpretation and re-evaluation of 620 offshore wells located in the UK portion of the SW Southern North Sea and 83 onshore wells located in Yorkshire and Lincolnshire (eastern England). The Zechstein Supergroup was interpreted in each well, and the data was used to compile seven SW-NE oriented correlation panels which show the development of the Supergroup in the study region. Five isopach maps for key formations in the Zechstein Supergroup were created, together with depositional environment maps for each of the main Zechstein carbonate formations. In combination, these regional-scale maps and diagrams have resulted in a consistent interpretation of the Zechstein Supergroup over an area which extends from the onshore outcrop in the west to the UKCS boundary in the Southern North Sea in the east.

Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this “Jarvis oil” is investigated in this paper using a multidisciplinary approach based on data from well-logs and cores from wells 20/02-2 and 20/02-3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic-oolitic packstones to shallow-subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing-upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM-rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C₂₈ steranes and C₂₈₊₂₉ monoaromatic and C₂₆R + C₂₇S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity.

This paper provides an updated understanding of the reservoir stratigraphy, sedimentology, palaeogeography and diagenesis of the Upper Permian Hauptdolomit Formation of the Zechstein Supergroup (“Hauptdolomit”) in a study area on the southern margin of the Mid North Sea High. The paper is based on the examination and description of core and cuttings data from 25 wells which were integrated with observations based on existing and new 3D seismic.

Based on thin-section petrography of cuttings and core from the wells studied, it is evident that Hauptdolomit microfacies are distributed in a relatively predictable way, and well-defined platform interior, platform margin, slope and basin settings can be distinguished. Platform margins are typically characterised by the development of ooid shoals and, to a lesser-extent, by microbial build-ups. High-energy back-shoal settings are characterised by a more complex combination of peloid grainstones, thrombolitic and microbial build-ups, and fine crystalline dolomites. Lower energy lagoons which developed further behind the platform margin are characterised by a variety of microfacies types; fine crystalline dolomites are common in this setting as well as peloidal facies and local microbial build-ups. Intertidal and supratidal settings are typified by increased proportions of anhydrite and the development of laminated microbial bindstones (stromatolites). Platform margins are in general relatively steep and pass into slope and basinal settings. Only a few wells have penetrated Hauptdolomit successions deposited in a slope setting, and these successions are characterised by a range of resedimented shallow-water facies together with low-energy laminated dolomicrites and fine crystalline dolomites. Slope zones in the study area are interpreted from seismic data to be typically 1-1.5 km in width. Basinal Hauptdolomit deposits have been strongly affected by post-depositional diagenesis and are dedolomitised to variable degrees. The original depositional facies are rarely preserved.

Diagenetic studies show that dolomitisation has affected almost the entire Hauptdolomit Formation throughout the study area in both basinal and platform settings. The dolomite is considered to result from seepage-reflux processes and is an early diagenetic phase. Mouldic porosity is present in many facies types as a result of dissolution, especially in ooid grainstones, thrombolitic build-ups and peloidal facies. The dissolution cannot be associated with any one diagenetic phase but was most likely a result of the dolomitisation process itself. Stable isotope analyses indicate that all dolomites were precipitated from Permian marine-derived pore fluids. Fluid inclusion analyses of dolomite cements indicate that cementation continued into the burial realm. Anhydrite cementation occurs in two phases: early anhydrite precipitation was associated with dolomitisation, and can be distinguished from a later, pore-filling cement

The so-called East Siberian “Basin” extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller-scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large-scale petroleum systems known. Proterozoic (“Riphean”: 1650-650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long-distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid-Devonian rift and has a later Palaeozoic and Mesozoic fill.

Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty-five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under-explored and none of the bitumen accumulations has yet been developed.

An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource-density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl)

Overpressure build up in the clay-rich succession between sea floor and the top of the Chalk Group in the area around wells North Jens-1 and Fasan-1 in the Danish sector of the Central Graben, North Sea was examined by forward modelling. “Overpressure”, i.e. fluid pressure higher than hydrostatic pressure, is expressed here in terms of both the difference between pore pressure and hydrostatic pressure at a given depth and the ratio between these pressures. Pore pressure changes over time were estimated by numerical simulation of post-Danian depositional processes, incorporating sea level changes and variations in sedimentation rate. Results show that the deposition of the post-Danian (“overburden”) succession led to overpressure build up both in the overburden itself and in the underlying sediments (the so-called “underburden”). The largest estimated present-day overpressures (4.9-5.6 MPa, 23-26% above hydrostatic) occur at the base of the overburden, while an overpressure of up to 5.5 MPa was calculated to occur in the underburden. Variations in sedimentation rate appeared to have influenced the build-up of overpressure in the overburden, although no significant effect was found in the underburden.

The results indicate that more than 50% of the present-day overpressure in the overburden was generated in the last 5.3 million years, i.e. during the Pliocene and the Quaternary. When variations in sedimentation rate during the Miocene were included in the modelling calculation, this proportion increased to nearly 70%. A decrease in sedimentation rate in the mid-Miocene (Serravallian, 15-11.2 Ma) and the late Miocene (Messinian, 7.5-5.3 Ma) resulted in the dissipation of overpressures generated previously when the sedimentation rate was higher. About 60% of the overpressure generated in the Miocene developed during the Tortonian but only 14% during the Messinian.

Water depth appears to influence the overpressure magnitude. Sea level changes played a minor and short-lived role in overpressure build up. The influence of water depth was most pronounced when it was significantly greater than the thickness of the deposited sediments.

The method of overpressure estimation used in this paper may be a valuable alternative to methods based on porosity trend analysis which are widely used in the oil and gas industry. Both the methods used here and the results may be useful in subsurface evaluations related to carbon storage in the Danish Central Graben (e.g. project Green Sand).