Middle Jurassic Reservoirs Research Articles

Geological history and petroleum system of the Mittelplate oil field, Northern Germany

The geological history of Germany’s largest and most productive petroleum accumulation, the Mittelplate oil field in Schleswig-Holstein (Northern Germany), is reconstructed by simulating the structural and thermal evolution along a 2D cross-section. The Mittelplate field is located at the western flank of the Busum salt dome at the transition from the Schleswig-Holstein mainland to the German North Sea Sector. Organic geochemical data confirm the Lower Jurassic Posidonia Shale to be the predominant oil source rock in the Schleswig-Holstein area. The studied section is characterized by salt walls and salt domes built up by Permian evaporites. Reconstruction of the structural and thermal evolution of the Mittelplate field by means of basin modelling reveals the dominating influence of salt dynamics on the entire petroleum system: The development of secondary rim-synclines during salt rise provided accommodation space for the deposition of the Posidonia Shale as well as the deltaic Middle Jurassic reservoir sandstones. The rise of the nearby Oldenswort salt wall controlled the timing of maturation and petroleum generation during Cenozoic times. Hydrocarbon migration from the Posidonia Shale into the reservoirs occurred up-dip from the deeper subsiding rim-syncline into the structural trap with the Middle Jurassic reservoir sandstones pinching out at the flank of the Busum salt dome. Along the modelled 2D section the field’s recent temperature field and its complex reservoir architecture are reconstructed.

The Heather Field, Block 2/5, UK North Sea

abstract The Heather oil field is located in Block 2/5 in the Northern North Sea. Oil is produced from sandstones of the Middle Jurassic Brent Group. at depths between 9500ft and 11600 ft below sea level. The field has been in production for over 20 years, and to date 120 MMSTB of oil have been produced out of an oil-in-place volume of 464 MMSTB. Although approaching non-commercial flow rates, an ambitious programme of field re-evaluation has been conducted since 1997 to identify remaining infill potential, and to investigate the development potential of satellite accumulations. New 3D seismic surveys shot in 1995 and 1997 have been combined to produce a continuous top reservoir map of the main field and adjacent satellite structures. The new mapping and an updated reservoir description were integrated with reservoir simulation models to identify zones of unswept oil. Main field infill projects have been identified which target the unswept oil, allowing extension of field life to be planned in conjunction with satellite field development. An additional 57 MMSTB of recoverable oil are expected to be produced from Middle Jurassic reservoirs in the main field and in satellite areas.

The permeability of faults within siliciclastic petroleum reservoirs of the North Sea and Norwegian Continental Shelf

Faulting in Middle Jurassic reservoirs occurred at shallow depth during regional extension. Clean sandstones (<15% clay) deformed without significant grain fracturing and permeability reduction. Faults in impure sandstones (15–40% clay) experienced significant syn-deformation compaction and permeability reduction. Enhanced compaction during deeper burial reduced their permeabilities further from an average of ∼0.05mD at <2.5km to ∼0.001mD at >4km. Clay-rich sediments (>40% clay) deformed to produce clay smears with very low permeabilities (<0.001mD). Faulting in the Rotliegendes occurred at greater depth during both basin extension and inversion. Extensional faulting produced cataclasites with permeability reductions of <10–>106; their permeabilities range from 0.2 to 0.0001mD and are inversely related to their maximum burial depth. Faults formed or reactivated during inversion experienced permeability increase. These results can be extrapolated to other hydrocarbon reservoirs if differences in stress and temperature history are taken into account.The permeability of most (>80%) faults is not sufficiently low, compared to their wallrock, to retard single-phase fluid flow on a km-scale. Nevertheless, most faults could retard the flow of a non-wetting phase if present at low saturations. It may be necessary to incorporate the two-phase fluid flow properties of fault rocks into reservoir simulators using upscaling or pseudoisation techniques. Fault property data should be calibrated against production data before it can be used confidently.

Source rock analysis and petroleum geochemistry of the Trym discovery, Norwegian North Sea: a Middle Jurassic coal-sourced petroleum system

The 3/7-4 well (Trym) in the Norwegian part of the Søgne Basin, North Sea, discovered condensates in Middle Jurassic reservoir sandstones and in addition penetrated four Middle Jurassic coal seams, 0.14–0.56 m thick. The precursor peats of the coals, which have a complex vitrinite- and inertinite-rich composition, accumulated in coastal plain mires, and the depositional conditions of the peats influenced the source rock potential of the resulting coals. Vitrinite reflectance values from 0.86–0.87% R o and an average T max of 438°C indicate that the coals are thermally mature, but they may be interpreted only to be in the early phase of petroleum generation. The Hydrogen Indices of the coals are generally below 200, and crude oil saturation of the coals may have been hindered by an uneven in-seam distribution of favourable Hydrogen Indices (>200) coupled with the comparatively thick seams. Condensate-source rock correlations indicate a similarity between the Trym condensates and extracts from the coals in the 3/7-4 well, and stable carbon isotope data infer a common source for the Trym condensates and the condensates and oils from the Harald and Lulita Fields in the Danish part of the Søgne Basin. The Harald and Lulita Fields have recently been proven to represent a Middle Jurassic coal-sourced petroleum system (the Lulu-Bryne/Lulu(!) Petroleum System), and the Trym condensate-discovery is thus another example of this petroleum system, which may be more widespread in the Central Graben.

Simulation of Mineral Diagenesis in Reservoirs. Application to Illite Formation in Feldspathic Sandstones: ABSTRACT

Petroleum geologists and production engineers are faced with reservoirs where porosities and permeabilities (poroperm) have been reduced by mineral phases precipitated during the geological evolution. Diagenesis of sandstones is influenced by many factors : initial composition of the sediment, burial history, composition of infiltrated waters. An appraisal of poroperm decline due to mineral diagenesis only can result from an integration of these factors. A quantitative evaluation of diagenetic phenomena is possible using numerical modelling. A first approach of the mineral transformations can be made using a new geochemical modelling software (NEWKIN) applied to closed cells, where aqueous solution and minerals are not in equilibrium initially. Cements of illite and quartz frequently occur in sandstones bearing feldspar, such as Middle Jurassic reservoirs of the Brent Group (East Shetland Basin, North Sea) which today lie between 3500 and 4500 in depth. Results of closed cells simulations are presented, which explore the conditions of illite and silica authigenesis in this Province, particularly in terms of temperature, water composition, and kinetics (oversaturation of the waters with respect to quartz, low pH). Another key of non-equilibrium, in pervious rocks, is the flow of interstitial water. Its role must be appraised by a -[open quotes]reaction-transport[close quotes]more » code. A new software is presented (DIAPHORE), able to solve, at the reservoir scale, in a coupled way : (1) advection of water and chemical elements in the porous volume; (2) mass balance of the considered chemical elements in the rock volume; (3) dissolution-precipitation phenomena occurring locally (using the geochemical code precedently described); (4) a feedback of the mineral transformations on permeability and reactive surface areas through a [open quotes]textural[close quotes] model at the grain scale.« less

Application of magnetostratigraphy to Brent Group reservoir zonation in the Visund Field

Abstract Magnetostratigraphy has been applied to an increasing number of oil fields in the North Sea region with promising results for detailed chronostratigraphic reservoir correlation. However, the magnetization processes in hydrocarbon reservoir successions, and the potential use of magnetostratigraphy for reservoir zonation purposes, are not very well known. Therefore, aspects of these subjects are discussed on the basis of a magnetostratigraphic study of three different wells covering the Middle Jurassic Brent Group at the Visund Field, northern North Sea. Results from scanning electron microscopy and remanent coercivity analysis suggest that the primary magnetization defining the magnetozones in the Brent Group is a combination of detrital remanent magnetization and a chemical remanent magnetization, probably acquired contemporaneously shortly after deposition. Detailed thermal demagnetization has uncovered an important secondary magnetization component in most of the core samples. This magnetization is probably due to cooling of the cores from a reservoir temperature of about 110°C to surface temperature, and it causes the main disturbances in the palaeomagnetic results. Based on analyses of individual core samples, characteristic remanent magnetization components have been defined. The magnetopolarity stratigraphy for the individual wells is based on these components and the results are comparable from well to well. The well correlation covers a rock sequence with a thickness of about 200m, and both magnetostratigraphic and biostratigraphic results have been used in combination with the lithostratigraphy. The acme of Corollina represents the most important palyno-event, and the top and bottom of this palynozone is used as the main tie-level for two of the wells. Sixteen additional correlation lines have been derived from the magnetostratigraphic results, six of these considered as tentative. The correlation reveals that the magnetostratigraphic results are facies independent and some of the lithostratigraphic formation lines appear to be diachronous within this deltaic mega-sequence. Although the magnetostratigraphy only provides a relative time framework for the Brent Group, the results are encouraging and suggest the possibility of achieving high resolution chronostratigraphic well correlations for Middle Jurassic reservoir sequences in the northern North Sea area.

Oil-source rock correlation in the North Viking Graben

Based on evaluation of geochemical properties of nearly 100 oils from the North Viking Graben, we have identified three hydrocarbon populations. One population is derived from marine shales of the Draupne Fm, one from marine shales of the Heather Fm, that are rich in land-plant detritus, and one from a mixture of the two. While the Draupne Fm is the dominant source rock, the Heather Fm (lower Callovian) is an important source on the northern Horda Platform. Furthermore, on the northern Horda Platform Heather Fm shales play a major role in controlling migration. Oil from the Draupne Fm migrates only into Upper Jurassic reservoirs, as no large titled fault blocks permit juxtaposition of Draupne Fm and Brent Gp sands, and the Heather Fm shales are thick and extensive. Oil from the Heather Fm migrates into both Upper and Middle Jurassic reservoirs. Variations in properties of the hydrocarbons in the North Viking Graben Petroleum System are due to a complex interplay of organic source, maturity, migration, pressure distribution and biodegradation. Integration of geochemical and geological data on a regional scale has enhanced our ability to evaluate prospects in this important hydrocarbon system.

Salinity variations in North Sea formation waters: implications for large-scale fluid movements

Sodium chloride is the major salt dissolved in formation waters, even at a considerable distance away from any evaporites. Chloride anions are not consumed to any significant extent by diagenetic reactions outside the salt deposits. Chloride ions are therefore preserved in the pore waters, and the distribution of pore water salinities in sedimentary basins may help to constrain pore water flow and the transport of dissolved species of silica and carbonate minerals. In the North Sea Basin and Haltenbanken (mid-Norway), salinity gradients can be inferred from formation water samples. Measurements of pore water salinity from wireline logs are less accurate than formation water samples, but have the advantage that a much larger database can be obtained. Data from 150 wells in the North Sea and Haltenbanken show that the salinities measured from well logs range from 20000 to 300000 ppm. In the southern part of the Norwegian North Sea and Haltenbanken, there is a clear trend towards higher salinities with greater burial depth. There is a pronounced salinity increase in the 500 m of section closest to the evaporites. In the northern North Sea, where underlying evaporites are not known, there is only a slight increase in the measured salinities with depth. There are, however, no measurements of high salinity pore water (>100000 ppm) at depths shallower than 2200 m. This pattern of salinity distribution in the pore water precludes large-scale convection of the pore water during diagenesis. It also indicates limited compaction-driven flow. Log-derived salinity data from the North Sea suggest that the pore waters in Upper Jurassic and Tertiary reservoirs are generally more saline than those of Middle and Lower Jurassic reservoirs at the same depth. The constraints on pore water flow that can be deduced from salinity variations puts severe limitations on the mechanisms of transport of dissolved solids in sedimentary basins and thus also on aspects of diagenetic models.

Sequence stratigraphic control on Middle and Upper Jurassic reservoir distribution within the UK Central North Sea

An integrated sequence stratigraphic analysis, utilizing seismic data, well-log cross-sections, biostratigraphic information, and core descriptions, provides a chronostratigraphic framework to analyse and predict the distribution of reservoir sandstones within the Middle to Upper Jurassic section of the UK Central North Sea. The Callovian (Middle Jurassic) through Ryazanian (lowermost Cretaceous) section in the UK Central North Sea forms a depositional wedge that thins towards the western graben margin. This wedge is bounded by surfaces traditionally interpreted as the Middle Cimmerian and Late Cimmerian unconformities. Marginal marine (Fulmar) sandstones are present within this wedge, and can be subdivided into informal lower and upper Fulmar members. Each member has a unique spatial and temporal distribution within the basin that can be related to primary depositional palaeogeography, post-depositional erosion, and basin tectonics. The lower member of the Fulmar Formation is Callovian to Early Oxfordian in age, and is restricted to the Central Graben. This member overlies Middle Jurassic strata of the Pentland Formation, and is conformably overlain by Oxfordian-age strata of the Kimmeridge Clay. The upper member of the Fulmar Formation is Early Kimmeridgian in age, and is distributed along the western graben margin. The upper member is conformably overlain by Kimmeridgian-age strata of Kimmeridge Clay, and typically overlies Triassic deposits of the Skagerrak Formation. Post-depositional erosion, association with relative falls in sea-level and accentuated by basement and salt tectonism, is the major factor that modifies primary depositional patterns within the Fulmar Formation. Truncation associated with unconformities interpreted as the 142 Ma, 138 Ma, and 136 Ma sequence boundaries affect the distribution, fades patterns, and thickness of the upper member of the Fulmar. These unconformities, as well as the 155.5 Ma, 150.5 Ma and 144 Ma sequence boundaries, may also affect the lower member of the Fulmar.

BIRKHEAD REVISITED: FETROLOGICAL AND GEOCHEMICAL STUDIES OF THE BIRKHEAD FORMATION, EROMANGA BASIN

Significant discoveries of oil have been made in Middle Jurassic sandstone reservoirs of the Birkhead Formation, Eromanga Basin, Australia.Some, or all, of this oil has been generated within the Birkhead Formation. A large proportion of the oil appears to be in relatively subtle traps. The source rock characteristics of the Birkhead Formation have been rated as fair to very good. In an attempt to improve the success rate in searching for less obvious reservoirs, a rating system based on the factors that control the location of hydrocarbon source rocks has been applied to many wells within the Birkhead Formation. The variables measured, which relate to source potential and maturation, were (1) thickness of shale units; (2) volume and type of dispersed organic matter; (3) volume and type of coal occurrences; and (4) rank.High values of source potential as measured by this rating system occur in the Birkhead Formation overlying the southwestern and northeastern parts of the Nappamerri Trough of the Cooper Basin. These areas include, or are close to, the known discoveries within the Birkhead Formation.In addition, investigation of the nature of the hydrocarbons produced from the Birkhead Formation using pyrolysis-gas chromatography (Py-GC) of whole rock samples and GC analysis of solvent extracts from the rocks indicates a terrestrial origin for the organic matter in most cases. Waxy oils could be expected from these samples under appropriate maturation conditions.

Platform-Stability Parameter Identification at Sea

Summary Dunlin field in the U.K. North Sea has been developed using reservoir simulation as a valuable tool in optimizing its exploitation. Simulation studies have been applied routinely to evaluate alternate development plans as well as to help understand the complex fluid movements in the reservoir. The paper presents examples of these applications. Introduction The Dunlin field, located in the northern North Sea, is owned jointly by Shell U.K. Exploration and Production, Esso Exploration and Production U.K., British Natl. Oil Corp., Gulf Oil Corp., and Conoco (U.K.) Ltd., and is operated by Shell. Since discovery in 1973, the field has been the subject of a flexible and continuously adaptable development plan. The initial plan was based on limited reservoir description from only a few wells and relatively widespread seismic data. Recognizing the limitations of the data, the development plan called for updating and improving the reservoir description as part of the initial steps of field development. The data from this early development needed rigorous evaluation to produce a final plan near optimum. One of the tools that has been very useful both in the data evaluation phase and the optimization phase of reservoir management is reservoir simulation. This paper includes major results of some of Esso E and P U.K. simulation studies of the Dunlin reservoir. Water encroachment into the highly stratified Brent (Middle Jurassic) reservoir can be understood best in terms of simulation studies. The extent and effect of restrictions to vertical flow in the reservoir are difficult to predict from geological studies, but use of history matching by reservoir simulation can quantify the hydraulic effect of these restrictions. The model then can become a useful tool on which to base management decisions for field development. The Esso reservoir simulation program has been used successfully to match the pressure and water cut performance at Dunlin. The cross-sectional model developed for the Main Fault Block at Dunlin has been used to understand how to manage the field effectively. Background Reservoir simulation has proved a valuable tool in management of the Dunlin reservoir. Dunlin, like other North Sea Viking Graben fields, presents a challenge to the reservoir manager trying to optimize field development and operation. The fields are, without exception, highly faulted and geologically complex. They require very large initial capital investment, which must be optimized relative to the development of the reservoir. Reservoir simulation enables the engineer to try out various development schemes before commitment to install a platform. It also can assess the sensitivity of the ultimate recovery to various unknowns in the early reservoir description. Ultimately, the simulation model can become an operational tool, regularly updated, to help understand the complexities of fluid movement within the reservoir. This paper addresses Esso's experience in evaluations of the Dunlin field development as an example of the use of reservoir simulation both for development planning and as a working tool in reservoir management. These studies have been undertaken by Esso to assist in decisions regarding the Dunlin Unit. JPT P. 227^