Fulmar Formation Research Articles

Low volumes of quartz cement in deeply buried Fulmar Formation sandstones explained by a low effective stress burial history

Upper Jurassic Fulmar Formation sandstones from the Fulmar Field in the Central North Sea are buried to 3.2 km and 128 °C but contain only 3.7 ± 1.7% (1σ) quartz cement, substantially less than volumes predicted by models based on temperature-related quartz precipitation kinetics. Oxygen isotope microanalysis of quartz overgrowths suggests that only limited cementation occurred at temperatures above 110 °C. We suggest that the anomalously low volumes of quartz cement are most readily explained by the effective stress history of the Fulmar Formation. Regional pore pressure analysis strongly suggests that pore fluid pressures in the Fulmar Formation decreased substantially in the last <0.5 Ma as a result of lateral seal failure, increasing effective stress from ca. 10 MPa to the current 31 MPa. A recent increase in effective stress is supported by the common occurrence of grains that are both fractured and unhealed by quartz cement. Intergranular pressure dissolution can account for around one third of the observed quartz cement, with the remainder from deep burial feldspar dissolution. We argue that the continuous history of low effective stress, until the very recent geological past, limited the rate of silica supply by intergranular pressure dissolution, and thus the rate of quartz cementation. Effective stress histories should be incorporated into predictive models of quartz cementation of sandstones.

The Importance of Effective Stress History on Quartz Cementation in Sandstones: Evidence from the Fulmar Formation, Central North Sea

The Importance of Effective Stress History on Quartz Cementation in Sandstones: Evidence from the Fulmar Formation, Central North Sea

Vertical effective stress and temperature as controls of quartz cementation in sandstones: Evidence from North Sea Fulmar and Gulf of Mexico Wilcox sandstones

Abstract We present quantitative petrographic data, high spatial resolution oxygen isotope analyses of quartz cement, basin modelling and a kinetic model for quartz precipitation for two Paleocene-Eocene Wilcox Group sandstones from Texas and two Jurassic Fulmar Formation sandstones from the Central North Sea. At each location, one sandstone has been buried to ca. 145 °C and one to ca. 185 °C. A key difference between the Wilcox and Fulmar burial histories is that the Wilcox sandstones are currently at higher vertical effective stresses and, from basin modelling studies, have been subjected to generally higher vertical effective stresses through their burial history. The amounts of quartz cement in the Wilcox sandstones are between 12 and 18%, and between 2 and 6% in the Fulmar sandstones. High-spatial-resolution oxygen isotope data obtained from the quartz cements suggest temperature ranges for quartz precipitation from 60 to 80 °C to values approaching maximum burial temperature. Factors such as grain coatings or the timing of petroleum emplacement cannot explain the differences in the amounts of quartz cement. Petrographic data show that most of the silica for quartz cement can be derived from intergranular pressure dissolution. Although the sample set is small, we interpret the results to suggest that the differences in quartz cementation in Fulmar and Wilcox sandstones can be explained better by differences in their vertical effective stress history than their temperature history; in this case, the supply of silica rather than the precipitation of quartz becomes an important control on the rate and extent of cementation.

Applications of real-time chemical stratigraphy in support of the safe drilling of HPHT wells: examples from the Shearwater Field, Central North Sea, UK

X-ray fluorescence (XRF) data from a series of high-pressure–high-temperature (HPHT) wells drilled in the Shearwater Field, UK Continental Shelf (UKCS) are presented. These data comprise a total of 789 samples across a series of eight study wells. Chemical stratigraphy was utilized in conjunction with other geological data (i.e. well logs, ditch cutting descriptions and biostratigraphic analyses) to aid real-time stratigraphic placement. Systematic changes in geochemical composition were identified and used to build a chemostratigraphic zonation to aid delineation of lithostratigraphic boundaries. The application of chemical stratigraphy provided a valuable source of data, particularly through critical ‘drill-in-liner’ sections that are devoid of conventional logging while drilling (LWD) data. The identification of key geochemical zones and provision of a synthetic gamma-ray (Synth GR) profile were utilized in the placement of key casing points and identification of challenging top reservoir picks (Fulmar Formation). These data also served as a backup during LWD tool failure resulting from excessive temperatures. The successive addition of geochemical data accumulated with each well-site exercise permitted continued refinement of the zonation framework, with derived Synth GR profiles exhibiting an extremely close relationship with subsequent wireline logs. Chemical stratigraphic data are shown to be robust and repeatable within the Shearwater Field, enabling close stratigraphic control through critical sections, whilst also providing a low-cost backup in the event of conventional logging tool failures.

The Acorn and Beechnut fields, Blocks 29/8a(S), 29/8b, 29/9a(S) and 29/9b, UK North Sea

Abstract Unocal discovered the Acorn South Field with wells 29/8b-2 and 29/8b-2s in 1983. The well and its side-track found a small accumulation of oil in Upper Jurassic, Fulmar Formation sandstones in an inter-pod setting. Well 29/8b-3 drilled two years later on what was thought to be the same structure found Acorn North, a larger accumulation of oil in a Triassic Skagerrak Formation reservoir on the crest of a Triassic pod. Premier discovered the Beechnut Field two years later, well 29/9b-2 finding oil in the Fulmar and Skagerrak formations in a faulted, inter-pod setting. Both Acorn and Beechnut are deep, high-pressure and high-temperature fields with complex reservoir stratigraphy due to halokinesis during sedimentation and post-depositional structuration. The Skagerrak Formation reservoir in Acorn North is appreciably poorer than similar-age reservoirs further north whilst the Fulmar Formation in Beechnut is relatively poorly developed. Acorn's mid-case oil in place is 90 MMbbl in the Skagerrak Formation and 13 MMbbl in the Fulmar Formation and, for Beechnut, is 15 MMbbl in the Fulmar Formation. Neither field has been developed. Limiting factors include the resource size, variable reservoir development (Beechnut), modest reservoir quality (Acorn North), compartmentalization concerns and development costs.

The Wood, Cayley, Godwin and Shaw fields, Blocks 22/17s, 22/18a and 22/22a, UK North Sea

Abstract The Upper Jurassic Wood, Godwin, Shaw and Cayley fields lie in Quadrant 22 on the Forties–Montrose High (FMH), a major intra-basinal high bisecting the Central Graben. The Wood Field was the first to be discovered in 1996 by Amoco. The field was later developed by Talisman Energy in 2007 via a single subsea horizontal producer tied back to the Montrose Alpha Platform. The Cayley, Godwin and Shaw discoveries followed during a drilling campaign carried out by Talisman Energy between 2007 and 2009 and were later developed, with the last field coming online in 2017. The fields are all complex structural and stratigraphic traps with reservoir in the Fulmar Formation. The Fulmar Formation on the FMH records an overall transgression, becoming progressively younger updip, with each field exhibiting a different diagenetic and depositional history in response to the unique evolution of the inter-pod in which they reside. The combined oil in place for the fields is currently estimated at 222 MMboe with an expected ultimate recovery of 84 MMboe. The addition of these reserves has been instrumental in helping to extend the life of the Montrose and Arbroath Platforms beyond 2030.

The Maria Field, Block 16/29a, UK North Sea

Abstract The Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.

The Elgin, Franklin, Glenelg and West Franklin fields, Blocks 22/30b, 22/30c, 29/4d, 29/5b and 29/5c, UK North Sea

Abstract The Elgin, Franklin, Glenelg and West Franklin fields lie approximately 240 km (150 miles) east of Aberdeen in Blocks 22/30b, 22/30c, 29/4d, 29/5b and 29/5c of the UK Central Graben. Franklin was discovered in 1985, Elgin in 1991, Glenelg in 1999 and West Franklin in 2003. Elgin is a complex faulted anticline comprising four panels, while the others are simpler, tilted fault block structures. The main reservoir is the Upper Jurassic Fulmar Formation shoreface sandstone, although the Middle Jurassic Pentland and Triassic Skagerrak formations have also been produced on Franklin. Initial pressure was c. 1100 bar (16 000 psi), with a reservoir temperature of around 190°C (375°F). Production wells are drilled from four wellhead platforms; all connected to a central process, utilities and quarters facility above Elgin. Gas and condensate production started in 2001 from six wells on each of Elgin and Franklin, with the plateau being extended by satellite and infill wells. The project remains the world's largest high-pressure–high-temperature development, requiring continued innovations in geoscience, drilling, completion and operations. Cumulative production at end 2017 is 886 Mboe, with estimated ultimate recovery around 1300 Mboe.

The Shearwater Field, Blocks 22/30b and 22/30e, UK North Sea

Abstract The Shearwater Field is a high-pressure–high-temperature (HPHT) gas condensate field located 180 km east of Aberdeen in UKCS Blocks 22/30b and 22/30e within the East Central Graben. Shell UK Limited operates the field on behalf of co-venturers Esso Exploration and Production UK Limited and Arco British Limited, via a fixed steel jacket production platform and bridge-linked wellhead jacket in a water depth of 295 ft. Sandstones of the Upper Jurassic Fulmar Formation constitute the primary reservoir upon which the initial field development was sanctioned; however, additional production has been achieved from intra-Heather Formation sandstones, as well as from the Middle Jurassic Pentland Formation. Following first gas in 2000, a series of well failures occurred such that by 2008 production from the main field Fulmar reservoir had ceased. This resulted in a shut-in period for the main field from 2010 before a platform well slot recovery and redevelopment drilling campaign reinstated production from the Fulmar reservoir in 2015. In addition to replacement wells, the redevelopment drilling also included the design and execution of additional wells targeting undeveloped reservoirs and near-field exploration targets, based on the lessons learned during the initial development campaign, resulting in concurrent production from all discovered reservoirs via six active production wells by 2018.

The Alma (formerly Argyll/Ardmore) Field, Blocks 30/24 and 30/25a, UK North Sea

Abstract The Alma Field (formerly Argyll and then Ardmore) is located within Blocks 30/24 and 30/25 on the western margin of the Central Graben. Hamilton drilled the first discovery well 30/24-1 in 1969 and the field, named ‘Argyll’, became the first UK offshore oilfield when production commenced in 1975. Oil was produced from the Devonian Buchan Formation, Permian Rotliegend and Zechstein groups, and Jurassic Fulmar Formation from 1976 until 1992, when the field was abandoned for economic reasons. In 2002, Tuscan Energy and Acorn Oil &amp; Gas redeveloped the field and renamed it as ‘Ardmore’. A further 5 MMbbl were produced until 2005, when the field was again abandoned due to commercial considerations. In 2011, EnQuest was awarded the licence to redevelop the field and renamed it as ‘Alma’. The field came on stream in October 2015 and has produced oil at an average c. 6000 bopd since start-up. Total ultimate recovery was expected to be about 100 MMbbl. As of end 2005, the field had produced 72.6 MMbbl as Argyll and 5 MMbbl as Ardmore. A further 4.3 MMbbl has been produced from the Alma Field to September 2017 (which includes about 0.5 MMbbl from a long-reach well drilled into the Duncan/Galia Field immediately west of Alma). In January 2020 EnQuest announced that the Alma Field would cease production early. The total production from the three phases of field development will be about 85 MMbbl of oil.

A STRATIGRAPHIC REVIEW OF THE LATE CALLOVIAN TO OXFORDIAN INTERVAL, FISHER BANK BASIN AREA (UK SECTOR, CENTRAL NORTH SEA)

The Middle to Upper Jurassic succession of six wells in the Fisher Bank Basin area has been reviewed within a consistent biostratigraphic framework. Significant, but age‐equivalent, vertical and lateral facies changes across the area have been demonstrated and a number of controlling factors are discussed. Several candidate Maximum Flooding Surfaces (MFSs) have been recognised, and various approaches to sequence stratigraphy in the Central North Sea are assessed. This has been particularly focused on the J40/J50 sequence boundary (top Middle Oxfordian) of Rattey and Hayward (1993) and its position with respect to the MFS picks of various authors. New analyses across the Port‐an‐Righ Ironstone MFS from an onshore outcrop and its correlation to the northern Moray Firth indicate that this may not be represented by the high gamma feature widely correlated throughout the Central North Sea, as the latter seems to occur at a slightly older level; it might occur as a more subdued feature, which is difficult to pick on logs in more heterogeneous settings.Sporomorph EcoGroup (SEG) analysis has allowed discussion of miospore assemblage fluctuations in response to various environmental factors such as climate change or sea level/base level fluctuations. Using marine palynomorphs whose distribution is essentially independent of lithology, detailed and consistent sub‐division and correlation of important Fulmar Formation reservoir sands allows direct comparison with the Heather and Kimmeridge Clay Formations in more distal settings. The transition from Fulmar Formation sands (reservoir) to Heather Formation shales (caprock) within the Armada Complex and SW Seymour gas fields is shown to be equivalent to an intra‐Kimmeridge Clay event in more distal wells.The current study emphasises the importance of having in place a dependable and well‐tested regional biostratigraphic framework as a basis for stratigraphic interpretation.

Monitoring shear deformations above compacting high-pressure high-temperature reservoirs with calliper surveys

Approximately thirty Multi-Finger Calliper (MFC) surveys have been acquired in Elgin and Franklin development wells between 2003 and 2013. These surveys reveal around one hundred shear deformation features characterized by a kink in the pipe. The calliper surveys were depth shifted against the open-hole reference depth used in Geoscience to accurately identify the interfaces along which the deformations occur. The deformations have been found to be distributed at the top of the Fulmar Formation reservoir, in the Late Jurassic shales, in the Early Cretaceous Cromer Knoll Group, and the Late Cretaceous Chalk Group. For each deformation feature, the relative displacement of the well was estimated using the calliper tool eccentricity resulting from the movement of the toolstring through the kink in the pipe. Maximum relative displacements were estimated at 3.7in. in the 7in. liner and at 1.2in. in the 9 7/8in. production casing. The analysis of the calliper surveys show that the deformation features result from slip displacements along various discontinuities such as bedding planes, reservoir faults extending in the overburden, and overburden faults. It is interpreted that these interfaces have been reactivated because of the strong reservoir depletion. This work clearly demonstrates that MFC surveys are an effective tool for monitoring shear deformations occurring above a compacting reservoir.

Managed-Pressure-Drilling Technology Delivers Challenging HP/HT Drilling Campaign

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175479, “MPD Technology Used To Deliver Challenging HP/HT Drilling Campaign,” by Robert Graham, Martin Geddes, Tim Harris, Dominic Flaherty, Nigel Shuttleworth, Bruce McEwan, Noor Nordin, Michael Cadd, John O’Grady, and Pete French, Shell, and Richard Sandell and Stuart Jeffries, Blade Energy Partners, prepared for the 2015 SPE Offshore Europe Conference and Exhibition, Aberdeen, 8–11 September. The paper has not been peer reviewed. The Shearwater field is a deep, high-pressure/high-temperature (HP/HT) reservoir located in the UK Central Graben of the North Sea. A high level of reservoir depletion (greater than 8,000 psi) has resulted in significant changes to the drilling envelope that has added complexity to the drilling practices required to exploit the remaining reserves successfully. Managed-pressure-drilling (MPD) technology was implemented in conjunction with drill-in liner and wellbore-strengthening technologies to successfully deliver the first well in a redevelopment campaign and prove the techniques required to prolong field life. Shearwater Overview Shearwater is an HP/HT gas/condensate field discovered in 1988. Primary production is from the Fulmar, a sandstone reservoir with virgin pressure of 15,400 psi and temperatures greater than 360°F. The field came on stream in 2001. The large field-pressure depletion resulted in compaction at the Fulmar formation level and led to mechanical failure of the production liners because of shear deformation. A drilling campaign to restore Fulmar production was initiated in 2013. The primary plan was to abandon the existing reservoir sections of the wells and perform shallow sidetracks from the 20-in. casing. A 16-in. hole was planned to the top of the Tor formation (above the pressure ramp), and a 12¼-in. hole was to be drilled into the top of the Cromer Knoll formation. 10×10¾-in. casing would be set across this hole section, and an 8½-in.-hole section would be drilled to just above the top of the Kimmeridge shale formation. A 7?-in. drill-in-liner system would then be used in conjunction with MPD and wellbore- strengthening material to drill into the top of the Fulmar reservoir. The reservoir was planned to be drilled with a 6½-in. hole size opened out to 7½ in., and the reservoir would be completed with a 7×5-in. production liner. The MPD objectives by hole section are discussed in detail in the complete paper. MPD was planned as an enabling technology because of the tight fracture-pressure/ pore-pressure wellbore- stability window. Fig. 1 illustrates the planned wellbore configuration and the expected pressure profiles.

Produced-Water-Chemistry History Matching in the Janice Field

Summary Produced-water-chemistry (PWC) data are the main sources of information to monitor scale precipitation in oilfield operations. Chloride concentration is used to evaluate the seawater fraction of the total produced water per producing well and is included as an extra history-matching constraint to reevaluate a good conventionally history-matched (HM) reservoir model for the Janice field. Generally, PWC is not included in conventional history matching, and this approach shows the value of considering the nature of the seawater-injection front and the associated brine mixing between the distinctive formation water and injected seawater. Adding the extra constraint resulted in the reconceptualization of the reservoir geology between a key injector and two producers. The transmissibility of a shale layer is locally modified within a range of geologically consistent values. Also, a major lineament is identified which is interpreted as a northwest/southeast-trending fault, whereby the zero transmissibility of a secondary shale in the Middle Fulmar is locally adjusted to allow crossflow. Both uncertainties are consistent with the complex faulting known to exist in the region of the targeted wells. Other uncertainties that were carried forward to the assisted-history-matching phase included water allocation to the major seawater injectors; thermal fracture orientation of injectors; and the vertical and horizontal permeability ratio (Kv/Kh) of the Fulmar formation. Finally, a stochastic particle-swarm-optimization (PSO) algorithm is used to generate an ensemble of HM models with seawater fraction as an extra constraint in the misfit definition. Use of additional data in history matching has improved the original good HM solution. Field oil-production rate is interpreted as improved over a key period, and although no obvious improvement was observed in field water-production rate, seawater fraction in a number of wells was improved.

Deep burial dissolution of K-feldspars in a fluvial sandstone, Pentland Formation, UK Central North Sea

The Pentland Formation of the UK Central North Sea is a quartzite in a sequence of more arkosic sandstones. Provenance-sensitive heavy mineral indices are interpreted to indicate that it was probably derived by erosion of arkosic sediments, which also supplied the arkosic marine sandstones of the contemporaneous Fulmar Formation. A lack of apatite within the Pentland Formation suggests that the feldspars could have dissolved during exposure to groundwaters during very shallow burial. However, petrographic and geochemical evidence supports survival of at least some of the feldspar to burial depths in excess of at least 2 km, when the sandstones had been stabilized against compaction by quartz cements or overpressure. Abundant kaolin, which has not reacted to form illite, is preserved at burial depths in excess of 4000 m, suggesting an unusual lack of available potassium. There is a strong contrast in diagenetic pathways with the overlying marine Fulmar Formation, which most probably had the same initial composition but in which kaolin is absent and fibrous illite is present. It is suggested that a lower concentration of potassium (and aluminium) within the Pentland Formation compared with the probable source and the comparably sourced Fulmar Formation represents export of K from the sands on a metre scale.

Episodic and simultaneous illitization in oil-bearing Brent Group and Fulmar Formation sandstones from the northern and southern North Sea based on illite K-Ar dating

Size fractions (0.4 and 0.4–1.0 m) of Brent Group sandstones from the northern North Sea contain mostly illite-smectite mixed layers with kaolinite, whereas the same size fractions of Fulmar Formation sandstones from the south-central North Sea consist of illite-smectite mixed layers with minor chlorite. Transmission electron microscope observations show elongated illite laths or agglomerates consisting of small laths when larger individual laths are lacking. The K-Ar data of the fractions less than 0.4 m of Brent Group samples plot on two arrays in a 40Ar/36Ar vs. 40K/36Ar diagram that have isochron characteristics with ages of 76.5 4.2 and 40.0 1.5 Ma, and initial 40Ar/36Ar ratios of 253 16 and 301 18, respectively. For the Fulmar Formation samples, the data points of the fractions less than 0.2 and less than 0.4 m also fit two isochrons with ages of 76.6 1.4 and 47.9 0.5 Ma and initial 40Ar/36Ar ratios of 359 52 and 304 2, respectively. Some of the coarser 0.4–1.0-m fractions also plot on the two isochrons, but most plot above indicating the presence of detrital components more than 0.4 m. The almost identical ages obtained from illite-type crystals of sandstones with different deposition ages that are located about 600 km (373 mi) apart record two simultaneous illitization episodes. These events were not induced by local burial conditions, but are related to episodic pressure and/or temperature increases in the studied reservoirs, probably induced by hydrocarbon injection. This interpretation is indirectly supported by notably different K-Ar illite ages from cores of a nearby reservoir at hydrostatic pressure. Illite is not as well crystallized as expected for potential crystallization temperatures above 160C measured by fluid-inclusion determinations. In both the northern and south-central North Sea, the two illite generations remain unaffected after crystallization despite continued burial, suggesting notably higher crystallization temperatures than those estimated from geothermal gradients. No recent illite crystallization or alteration is recorded in the K-Ar ages, despite a dramatic regional acceleration of the subsidence in the southern North Sea.

Oil charge preserves exceptional porosity in deeply buried, overpressured, sandstones: Central North Sea, UK

Abstract: Exceptionally high-porosity sandstones are reported from oil provinces worldwide, yet the mechanism of porosity preservation remains controversial. We present strong evidence that the exceptional porosities in the Jurassic Fulmar Formation within the North Sea are the result of early oil charging preventing cementation and chemical compaction in sands with relatively low detrital clay contents, although overpressure and grain coatings do have some effect. The most dramatic evidence that reservoir quality is related to early oil charge is the spatial distribution of the porosity: the maximum porosity of the Fulmar Formation is systematically highest immediately below the top seal, and decreases below this despite uniform sedimentology. Hence, porosity is preferentially preserved where oil first accumulated in these unusually homogeneous overpressured reservoir sandstones, at the top. Oil charge prevents or significantly retards chemical compaction and cementation of a reservoir, preserving porosity. There is independent evidence for early oil charging of reservoirs within the Central Graben, from fluid inclusion studies and K–Ar age dates of authigenic illite. Micro-quartz grain coatings, which have been proposed to preserve porosity during burial, are associated with only 5% extra porosity in sands that exceed the worldwide average sandstone porosity by almost 20%.

Chemostratigraphy of upper Jurassic reservoir sandstones, Danish Central Graben, North Sea

A chemostratigraphic study of Upper Jurassic sandstones in the northern Danish Central Graben has been undertaken within the framework of a well-defined stratigraphic/sedimentological model based particularly on cored well sections. Two reservoir sandstone units are recognised, the transgressive marginal marine to shoreface sandstone of the Gert Member and the regressive to transgressive shoreface sandstone of the Ravn Member. Both members belong to the Heno Formation, which is equivalent to the Fulmar Formation (UK) and the Ula Formation (Norway). Multivariate analysis of geochemical data from 264 core samples from 8 wells reveals the distinction between the two reservoir sandstones (Gert and Ravn members) and the two offshore claystones (Farsund and Lola formations). Specific elements have proven to be important for this separation and these elements demonstrate differences even in 2-dimensional cross plots. The Farsund Formation is characterised by higher V, U and P 2O 5, and lower MgO and K 2O when compared with the Lola Formation. The Gert Member typically has higher maximum amounts of Cr and TiO 2 than the Ravn Member. The high Cr and TiO 2 content (probably from chrome spinel and Ti-minerals) might be related to a source of exposed Carboniferous sediments in the Gert Ridge area. The Ravn Member is characterised by higher Na 2O, P 2O 5 and Th contents than the Gert Member, which may reflect a higher content of plagioclase (Na 2O) and a changed heavy mineral assemblage. The Mid North Sea High is a likely source for the heavy mineral suite that characterises the Ravn Member. The Rita-1 well, situated closest to the Mid North Sea High, seems to have been more influenced by this source than the other wells. In the Hejre area, a volcanic source supplying K-feldspar may be responsible for the relatively high K 2O/Al 2O 3 observed in both the Gert and Ravn members. Hence in addition to differentiation between the two reservoir sands and between the two offshore claystones, this study also illustrates the use of geochemical data for evaluation of source characteristics and dominance of different sediment source areas.

Upper Jurassic reservoir sandstones in the Danish Central Graben: new insights on distribution and depositional environments

Abstract Recently available well data from the northern part of the Danish Central Graben have been analysed to further understand the basin development, biostratigraphy, depositional models and palaeogeography of Upper Jurassic reservoir sandstones, which are the primary exploration targets in this basin. Notably, the discovery of the Hejre accumulation in 2001, where oil has been encountered in Upper Jurassic good reservoir quality sandstones at a depth of more than 5000 m, triggered renewed interest in the Upper Jurassic High Temperature–High Pressure sandstone play in the area. Overall the Danish Central Graben was transgressed from east to west during the Late Jurassic. During the Late Kimmeridgian, marginal and shallow marine sandstones assigned to the Heno Formation were deposited at the margin of the Feda Graben, and on the Gertrud and Heno Plateaus and constitute the reservoirs in the Freja and Hejre discoveries. The sandstones are analogues to the UK Fulmar and Norwegian Ula Formations encountered in several hydrocarbon fields. During the Early Volgian, the transgression continued westwards across the Outer Rough Basin along the margin of the Mid North Sea High, where shoreface sandstones with excellent porosities and permeabilities were deposited close to similar sandstones of the Fulmar Formation in the British Fergus, Fife and Angus fields. During this overall westward transgression, the eastern and central parts of the Danish Central Graben continued to subside and offshore mudstones accumulated, locally intercalated with gravity-flow sandstones. In the easternmost Danish Central Graben, in the Tail End Graben, Upper Kimmeridgian gravity-flow sandstones of the Svane-1 well have proved the presence of gas at c . 6 km depth. Hydrocarbon-bearing Upper Jurassic sandstone reservoirs at significant depths (deeper than 5 km) may form the future exploration targets in the northern part of the Danish Central Graben.

Hydrocarbon filling and leakage history of a deep geopressured sandstone, Fulmar Formation, United Kingdom North Sea

Diagenetic minerals in a water-filled borehole from the Jurassic Fulmar Formation, United Kingdom central North Sea, record two phases of hydrocarbon filling and emptying. Initial oil charge was during the Late Cretaceous, at shallow burial depths of about 1.5 km (0.9 mi). As we consider that hydrocarbon has preserved porosity during burial, this has implications for the understanding of the porosity evolution of the Fulmar Formation, which, in other locations, is an important hydrocarbon reservoir. The early oil charge, as recorded by illite K-Ar ages, progressively filled the structure from 84 to 59 Ma, and possibly precipitated bitumen because of biodegradation. The first oil predated many of the burial diagenetic reactions within the sandstone. After leak-off at ca. 60 Ma, diagenetic reactions continued in an open geochemical system, with possible import of CO2. Products of these reactions include ankerite and quartz overgrowth cements. Hydrocarbon staining postdates these phases and provides evidence of a hydrocarbon charge, probably gas condensate. The second hydrocarbon charge also leaked off, and the sandstone is now water bearing. Previous work on the Fulmar Formation has incorrectly placed all the diagenetic reactions as predating the first arrival of hydrocarbon. The present-day pore fluids are high-salinity, high-δ18O fluids derived from the underlying Permian Zechstein evaporates. These fluids entered the reservoir during a phase of overpressure release that caused fracturing of the framework quartz grains, possibly coincident with the second phase of hydrocarbon leak-off at 2–5 Ma. Mark Wilkinson studied sandstone-hosted calcite concretions for his Ph.D. and has subsequently tried to take a more holistic view of the diagenesis of sedimentary basins. His career has been funded by a variety of oil companies, although he is currently involved in geological disposal of some of the CO2 that he was partly responsible for producing. Stuart Haszeldine is a professor at Edinburgh University. He received his Ph.D. on clastic and coal sedimentology in 1981 from the University of Strathclyde. After an attempted reeducation in the oil industry, he has collaborated with many companies to research on hydrocarbon reservoir quality, radioactive waste disposal, and coal resources. He currently heads the United Kingdom's largest group investigating carbon dioxide sequestration. Tony Fallick was educated at the University of Glasgow, Scotland, in physics (B.Sc.) and chemistry (Ph.D.). He did research at McMaster University, Ontario, Canada, and Cambridge, England, before moving in 1980 to the Scottish Universities Research and Reactor Center, where he is currently the director.