North sea

@book{parker1977lower2,
    author = "Parker, J. R",
    title = "Lower Tertiary sand development in the central North Sea, in Developments in Petroleum Geology",
    year = "1977",
    publisher = "Essex, England, Applied Science Publications, Limited, v. 1, p. 447-453",
    note = "talkorigins\_source = {true}; raw\_reference = {Parker, J. R., 1977, Lower Tertiary sand development in the central North Sea, in Developments in Petroleum Geology: Essex, England, Applied Science Publications, Limited, v. 1, p. 447-453.}"
}

@article{feheritier1978frigg,
    author = "F. E. Heritier, P. Lossel, E. Wathn",
    title = "Frigg Field--Large Submarine-Fan Trap in Lower Eocene Sandstones of North Sea Viking Graben: ABSTRACT",
    year = "1978",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/c1ea4aa4-16c9-11d7-8645000102c1865d",
    doi = "10.1306/c1ea4aa4-16c9-11d7-8645000102c1865d",
    volume = "62"
}

In the deepest, axial part of the Viking subbasin of the North Sea, the Frigg field, one of the world’s largest offshore gas fields, straddles the border of the British and Norwegian continental shelf at lat. 60°N. The discovery well was drilled in 1971 on Norwegian block 25/1 in 100 m of water. Gas was discovered at a depth of 1,850 m in a lobate submarine fan representing the ultimate phase of a thick Paleocene deposit. Sealed by middle Eocene open marine shales, the structure is mainly submarine-fan depositional topography enhanced by draping and differential compaction of sands. The area of structural closure is underlined by a typical “flat spot” on seismic sections and the gas column lies on a heavy oil disk. Chromatographic analysis shows that both oil and gas could be coming from underlying Jurassic source rocks. Recoverable gas reserves are estimated to be about 200 billion cu m (7 Tcf). Production began September 15, 1977; the gas is brought ashore at St. Fergus in Scotland by a 360-km pipeline.

@article{heritier1979frigg,
    author = "HERITIER, F. E. and LOSSEL, P. and WATHNE, E.",
    title = "Frigg Field—Large Submarine-Fan Trap in Lower Eocene Rocks of North Sea Viking Graben",
    year = "1979",
    journal = "AAPG Bulletin",
    abstract = "In the deepest, axial part of the Viking subbasin of the North Sea, the Frigg field, one of the world’s largest offshore gas fields, straddles the border of the British and Norwegian continental shelf at lat. 60°N. The discovery well was drilled in 1971 on Norwegian block 25/1 in 100 m of water. Gas was discovered at a depth of 1,850 m in a lobate submarine fan representing the ultimate phase of a thick Paleocene deposit. Sealed by middle Eocene open marine shales, the structure is mainly submarine-fan depositional topography enhanced by draping and differential compaction of sands. The area of structural closure is underlined by a typical “flat spot” on seismic sections and the gas column lies on a heavy oil disk. Chromatographic analysis shows that both oil and gas could be coming from underlying Jurassic source rocks. Recoverable gas reserves are estimated to be about 200 billion cu m (7 Tcf). Production began September 15, 1977; the gas is brought ashore at St. Fergus in Scotland by a 360-km pipeline.",
    url = "https://doi.org/10.1306/2f918856-16ce-11d7-8645000102c1865d",
    doi = "10.1306/2f918856-16ce-11d7-8645000102c1865d",
    number = "11",
    pages = "1999-2020",
    volume = "63"
}

@techreport{heritier1979frigg1,
    author = "Heritier, F. E. and Lossel, P. and Wathne, E",
    title = "Frigg Field - large submarine fan trap in lower Eocene rocks of the North Sea",
    year = "1979",
    howpublished = "American Association of Petroleum Geologists Bulletin, v. 63, p. 1999-2020",
    note = "talkorigins\_source = {true}; raw\_reference = {Heritier, F. E., Lossel, P., and Wathne, E., 1979, Frigg Field - large submarine fan trap in lower Eocene rocks of the North Sea: American Association of Petroleum Geologists Bulletin, v. 63, p. 1999-2020.}"
}

Summary This paper reviews U.K. Continental Shelf (UKCS) field developments to date for technical features, development time scales, and economics. Current UKCS field-development trends are identified, including use of subsea completions and floating production platforms (FPP's) for development of small deepwater fields. Economic comparisons are presented for a range of field developments under existing U.K. tax and fiscal regimes. The effects of unstable oil prices on rates of return (ROR's) are discussed, together with the effect prices on rates of return (ROR's) are discussed, together with the effect of tax changes on field economics. Introduction The North Sea is a mature oil province in which current developments represent the third generation. Total UKCS oil production passed its peak rate during 1985, and attention must focus increasingly on investment in new fields to replace declining production from the 30 oil fields now on stream. The current economic climate, however, is unfavorable to new investment in UKCS oil fields. World oil prices* collapsed from $31/bbl [$195/m3] in Nov. 1985 prices* collapsed from $31/bbl [$195/m3] in Nov. 1985 to below $9/bbl [$57/m3] in July 1986, recovering to around $14/bbl [$88/m3] in Oct.86. This oil price collapse of 70% within 9 months has dealt a staggering blow to our industry, which has seen a decline of some 6 x 10 6 B/D [0.95 x 10 6 m3/d] in total free-world oil demand since 1979. The situation is further exacerbated because future UKCS projects will develop fields of steadily diminishing size in terms of recoverable reserves. This dual penalty of reduced field size for development and markedly lower oil prices makes it very difficult at this time to justify needed new investment in UKCS oil fields. The prospect for continuing development of UKCS gas fields appears healthier. Gas developments relate more closely to those for alternative sources of primary energy, such as coal or nuclear power. Gas supply contracts are long-term rather than spot-market related, with specified prices and minimum offtake quantities, take-or-pay clauses, and strict formulas for price adjustments. Such measures are necessary to safeguard the large investment in fully dedicated field facilities and the infrastructure of an export pipeline and onshore terminal needed to get the gas to the particular market to which it has been contracted. UKCS gas contracts have traditionally embodied price indexing on the basis of a balanced mixture of oil, other primary energy, and general inflation factors. As a result primary energy, and general inflation factors. As a result of the oil price collapse, more emphasis is likely in new gas supply contracts on oil and oil products price indexing, perhaps also with an oil-price-linked override to allow for perhaps also with an oil-price-linked override to allow for sharp and sustained falls in oil and products prices. Potential UKCS gas resources and projected U.K. gas demand are closer to being in balance, with most analysts predicting a net shortfall by the mid-1990's. Thus predicting a net shortfall by the mid-1990's. Thus overall prospects for the UKCS, in particular southern basin gas developments, remain fairly good, as evidenced by the continuation of such projects as Conoco's V-fields and Lincolnshire Offshore Gas Gathering System (LOGGS) and British Petroleum's (BP) Cleeton and Ravenspurn South fields, including a new trunkline and onshore terminal. This contrasts sharply with recent setbacks to major oilfield developments, such as Shell Esso's Gannet/Kittiwake complex or BP Conoco's Miller. For these and other potential UKCS oilfield developments, major reviews are necessary to cut costs substantially in response to the oil price collapse. Now seems an appropriate time to review historic costs, development trends, and economics for aid in future field developments. The precise timing for a number of these developments remains in question, but there can be little doubt that the majority of UKCS fields remaining for development will be produced in due course. This paper is confined to consideration of only UKCS fields, with reference being made to others where appropriate. Southern Basin Gasfield Developments In 1959 a giant onshore gas field was discovered at Groningen, northern Holland, in Permian Rotliegende sandstone formations. This event sparked the search for hydrocarbons in the North Sea. From the mid-1960's, a number of Permian gas fields were discovered in a trend stretching across the southern North Sea from Holland to the U.K., which is still being drilled intensively. Table I gives a chronology and summary of facilities, and Table 2 gives a summary of costs and economics, for UKCS southern basin gas fields. Capital costs for these developments are low compared with those for North Sea oil fields. However, real ROR's for the earlier projects are low because of very low gas prices negotiated by British Gas when it was the monopoly prices negotiated by British Gas when it was the monopoly buyer. JPT p. 1311

@article{thomas1986north,
    author = "Thomas, W.A.",
    title = "North Sea Field Developments: Historic Costs and Future Trends",
    year = "1986",
    journal = "Journal of Petroleum Technology",
    abstract = "Summary This paper reviews U.K. Continental Shelf (UKCS) field developments to date for technical features, development time scales, and economics. Current UKCS field-development trends are identified, including use of subsea completions and floating production platforms (FPP's) for development of small deepwater fields. Economic comparisons are presented for a range of field developments under existing U.K. tax and fiscal regimes. The effects of unstable oil prices on rates of return (ROR's) are discussed, together with the effect prices on rates of return (ROR's) are discussed, together with the effect of tax changes on field economics. Introduction The North Sea is a mature oil province in which current developments represent the third generation. Total UKCS oil production passed its peak rate during 1985, and attention must focus increasingly on investment in new fields to replace declining production from the 30 oil fields now on stream. The current economic climate, however, is unfavorable to new investment in UKCS oil fields. World oil prices* collapsed from $31/bbl [$195/m3] in Nov. 1985 prices* collapsed from $31/bbl [$195/m3] in Nov. 1985 to below $9/bbl [$57/m3] in July 1986, recovering to around $14/bbl [$88/m3] in Oct.86. This oil price collapse of 70\% within 9 months has dealt a staggering blow to our industry, which has seen a decline of some 6 x 10 6 B/D [0.95 x 10 6 m3/d] in total free-world oil demand since 1979. The situation is further exacerbated because future UKCS projects will develop fields of steadily diminishing size in terms of recoverable reserves. This dual penalty of reduced field size for development and markedly lower oil prices makes it very difficult at this time to justify needed new investment in UKCS oil fields. The prospect for continuing development of UKCS gas fields appears healthier. Gas developments relate more closely to those for alternative sources of primary energy, such as coal or nuclear power. Gas supply contracts are long-term rather than spot-market related, with specified prices and minimum offtake quantities, take-or-pay clauses, and strict formulas for price adjustments. Such measures are necessary to safeguard the large investment in fully dedicated field facilities and the infrastructure of an export pipeline and onshore terminal needed to get the gas to the particular market to which it has been contracted. UKCS gas contracts have traditionally embodied price indexing on the basis of a balanced mixture of oil, other primary energy, and general inflation factors. As a result primary energy, and general inflation factors. As a result of the oil price collapse, more emphasis is likely in new gas supply contracts on oil and oil products price indexing, perhaps also with an oil-price-linked override to allow for perhaps also with an oil-price-linked override to allow for sharp and sustained falls in oil and products prices. Potential UKCS gas resources and projected U.K. gas demand are closer to being in balance, with most analysts predicting a net shortfall by the mid-1990's. Thus predicting a net shortfall by the mid-1990's. Thus overall prospects for the UKCS, in particular southern basin gas developments, remain fairly good, as evidenced by the continuation of such projects as Conoco's V-fields and Lincolnshire Offshore Gas Gathering System (LOGGS) and British Petroleum's (BP) Cleeton and Ravenspurn South fields, including a new trunkline and onshore terminal. This contrasts sharply with recent setbacks to major oilfield developments, such as Shell Esso's Gannet/Kittiwake complex or BP Conoco's Miller. For these and other potential UKCS oilfield developments, major reviews are necessary to cut costs substantially in response to the oil price collapse. Now seems an appropriate time to review historic costs, development trends, and economics for aid in future field developments. The precise timing for a number of these developments remains in question, but there can be little doubt that the majority of UKCS fields remaining for development will be produced in due course. This paper is confined to consideration of only UKCS fields, with reference being made to others where appropriate. Southern Basin Gasfield Developments In 1959 a giant onshore gas field was discovered at Groningen, northern Holland, in Permian Rotliegende sandstone formations. This event sparked the search for hydrocarbons in the North Sea. From the mid-1960's, a number of Permian gas fields were discovered in a trend stretching across the southern North Sea from Holland to the U.K., which is still being drilled intensively. Table I gives a chronology and summary of facilities, and Table 2 gives a summary of costs and economics, for UKCS southern basin gas fields. Capital costs for these developments are low compared with those for North Sea oil fields. However, real ROR's for the earlier projects are low because of very low gas prices negotiated by British Gas when it was the monopoly prices negotiated by British Gas when it was the monopoly buyer. JPT p. 1311",
    url = "https://doi.org/10.2118/12984-pa",
    doi = "10.2118/12984-pa",
    number = "11",
    pages = "1211-1220",
    volume = "38"
}

Continued progress in matters of frontier resource development is dependent on avoidance of past errors. The development of oil and gas fields in the hostile North Sea environment represents a major pioneering effort which has witnessed the successful introduction of many new technologies. Evaluation of the success of North Sea ventures has, however, been confused by the impact of inflation and currency realignments.A recent analysis by Castle) of North Sea field Economic performance suggests that these fields would have been ‘underwater’ (due to technical under performance) if they had not been "bailed out" by the crude oil price increases, particularly of 1979. Examined are the technical factors responsible for Castle's observation for certain fields and it is concluded that greater care is needed in relating reservoir performance uncertainty to pre-development appraisal well data. Attempts are made to highlight some of the potential problem areas encountered when defining a development plan with the help of reservoir simulationmodels. Analyzed are published data for two typical North Sea fields: Thistle and Beatrice, which are amplified with observations from personal experience. Introduction Table 1 is partly extracted from a recent article by Castle(l) where an attempt was made to estimate how profitable 19 North Sea fields would have been if prices had remained flat from the time development was initiated. These "proforma" rate-of-return estimates, which ignore petroleum revenue tax as well as corporate taxes, and only deduct the 12? % royalty, indicated that only 14 fields in fact yielded a positive cash flow and of these only 7 yielded a rate of return in excess of 15%. At first glance Castle's analysis leads one to conclude that the performance of the oil industry in the North Sea was, in real terms, an economic disappointment. Table 1 has been enlarged with technical performance data extracted from the United Kingdom Brown Book(2). It is well known that the oil industry and various northwestern European National Treasuries have derived much benefit from the North Sea Oil Province. In terms of money of the day, the rates-of-return have been more than adequate to permit rapid payback of loans, a very large government "take", as well as to fund further developments. This is due, as Castle points out, to inflation and currency fluctuations ‘bailing out’ the North Sea projects most of which suffered from construction delays, cost overruns and production shortfalls. In this paper an attempt is made to identify the main technical reasons for under-performance of two of Castle's fields: Thistle and Beatrice (Fig. 1), These fields are rather well documented (see reference list) and thus provide much study material. This sample moreover includes a typical "Brent Province" Jurassic field representing one of the pioneering developments, as well as a later, non-Brent "marginal discovery" benefitting from five years of offshore technological progress. It is, therefore, a representative sample, and gives a fair insight into the technical risks inherent in offshore developments. Within the context of U.K offshore developments, both fields are successful.

@article{vanoort1988lessons,
    author = "Van Oort, B.",
    title = "Lessons Learned In North Sea Oil Field Developments",
    year = "1988",
    journal = "Journal of Canadian Petroleum Technology",
    abstract = {Continued progress in matters of frontier resource development is dependent on avoidance of past errors. The development of oil and gas fields in the hostile North Sea environment represents a major pioneering effort which has witnessed the successful introduction of many new technologies. Evaluation of the success of North Sea ventures has, however, been confused by the impact of inflation and currency realignments.A recent analysis by Castle) of North Sea field Economic performance suggests that these fields would have been ‘underwater’ (due to technical under performance) if they had not been "bailed out" by the crude oil price increases, particularly of 1979. Examined are the technical factors responsible for Castle's observation for certain fields and it is concluded that greater care is needed in relating reservoir performance uncertainty to pre-development appraisal well data. Attempts are made to highlight some of the potential problem areas encountered when defining a development plan with the help of reservoir simulationmodels. Analyzed are published data for two typical North Sea fields: Thistle and Beatrice, which are amplified with observations from personal experience. Introduction Table 1 is partly extracted from a recent article by Castle(l) where an attempt was made to estimate how profitable 19 North Sea fields would have been if prices had remained flat from the time development was initiated. These "proforma" rate-of-return estimates, which ignore petroleum revenue tax as well as corporate taxes, and only deduct the 12? \% royalty, indicated that only 14 fields in fact yielded a positive cash flow and of these only 7 yielded a rate of return in excess of 15\%. At first glance Castle's analysis leads one to conclude that the performance of the oil industry in the North Sea was, in real terms, an economic disappointment. Table 1 has been enlarged with technical performance data extracted from the United Kingdom Brown Book(2). It is well known that the oil industry and various northwestern European National Treasuries have derived much benefit from the North Sea Oil Province. In terms of money of the day, the rates-of-return have been more than adequate to permit rapid payback of loans, a very large government "take", as well as to fund further developments. This is due, as Castle points out, to inflation and currency fluctuations ‘bailing out’ the North Sea projects most of which suffered from construction delays, cost overruns and production shortfalls. In this paper an attempt is made to identify the main technical reasons for under-performance of two of Castle's fields: Thistle and Beatrice (Fig. 1), These fields are rather well documented (see reference list) and thus provide much study material. This sample moreover includes a typical "Brent Province" Jurassic field representing one of the pioneering developments, as well as a later, non-Brent "marginal discovery" benefitting from five years of offshore technological progress. It is, therefore, a representative sample, and gives a fair insight into the technical risks inherent in offshore developments. Within the context of U.K offshore developments, both fields are successful.},
    url = "https://doi.org/10.2118/88-06-11",
    doi = "10.2118/88-06-11",
    number = "06",
    volume = "27"
}

@article{spencerrwinter1989alba,
    author = "Spencer R. Winter, Henry H. Brettha",
    title = "Alba Field--Middle Eocene Deep-Water Channel in U.K. North Sea: ABSTRACT",
    year = "1989",
    journal = "AAPG Bulletin",
    url = "https://doi.org/10.1306/44b49f79-170a-11d7-8645000102c1865d",
    doi = "10.1306/44b49f79-170a-11d7-8645000102c1865d",
    volume = "73"
}

FIELD CLASSIFICATION: BASIN: North Sea BASIN TYPE: Rift RESERVOIR ROCK TYPE: Limestone (Chalk) RESERVOIR ENVIRONMENT OF DEPOSITION: Resedimented Chalk RESERVOIR AGE: Paleocene PETROLEUM TYPE: Gas And Condensate TRAP TYPE: Dome Overlying Salt Diapir

@article{dheur1991west,
    author = "D’Heur, Michel",
    title = "West Ekofisk Field–Norway, Central Graben, North Sea",
    year = "1991",
    journal = "AAPG Bulletin",
    abstract = "FIELD CLASSIFICATION: BASIN: North Sea BASIN TYPE: Rift RESERVOIR ROCK TYPE: Limestone (Chalk) RESERVOIR ENVIRONMENT OF DEPOSITION: Resedimented Chalk RESERVOIR AGE: Paleocene PETROLEUM TYPE: Gas And Condensate TRAP TYPE: Dome Overlying Salt Diapir",
    url = "https://doi.org/10.1306/0c9b28a3-1710-11d7-8645000102c1865d",
    doi = "10.1306/0c9b28a3-1710-11d7-8645000102c1865d",
    number = "5",
    pages = "946-968",
    volume = "75"
}

The Fife Field is located in the far southeastern part of the Central North Sea Basin close to the UK, Norwegian, Danish median line. The field is a shallow relief four-way dip closure formed by inversion during Late Cretaceous/ early Tertiary times. The reservoir consists of thick Upper Jurassic, heavily bioturbated sandstones which are considered to have been deposited in a similar setting to the Fulmar Formation. The depth to the top of the Upper Jurassic at the crest of the field is 8250 ft sub-sea with the oil-water contact at 8512 ft sub-sea. The seal to reservoir is provided by Volgian-Ryazanian shales of the Kimmeridge Clay Formation and Upper Cretaceous Chalk. Although Jurassic sandstones form the primary reservoir, additional hydrocarbons have been encountered in the Tor Formation of the Chalk Group which is fractured over the crest of the field. The Fife Field was discovered in 1991 and is currently under development. Production started in August 1995 via the 'Uisge Gorm' Floating Production Storage and Offloading facility (FPSO). STOIIP is estimated at 132 x 106BBL and ultimate recovery is predicted to be 34 x 106 BBL oil. The low mobility of the oil and the low vertical permeability of the reservoir contribute to the predicted low (26%) recovery efficiencies.

@article{mackertich1996the,
    author = "Mackertich, David",
    title = "The Fife Field, UK central North Sea",
    year = "1996",
    journal = "Petroleum Geoscience",
    abstract = "The Fife Field is located in the far southeastern part of the Central North Sea Basin close to the UK, Norwegian, Danish median line. The field is a shallow relief four-way dip closure formed by inversion during Late Cretaceous/ early Tertiary times. The reservoir consists of thick Upper Jurassic, heavily bioturbated sandstones which are considered to have been deposited in a similar setting to the Fulmar Formation. The depth to the top of the Upper Jurassic at the crest of the field is 8250 ft sub-sea with the oil-water contact at 8512 ft sub-sea. The seal to reservoir is provided by Volgian-Ryazanian shales of the Kimmeridge Clay Formation and Upper Cretaceous Chalk. Although Jurassic sandstones form the primary reservoir, additional hydrocarbons have been encountered in the Tor Formation of the Chalk Group which is fractured over the crest of the field. The Fife Field was discovered in 1991 and is currently under development. Production started in August 1995 via the 'Uisge Gorm' Floating Production Storage and Offloading facility (FPSO). STOIIP is estimated at 132 x 106BBL and ultimate recovery is predicted to be 34 x 106 BBL oil. The low mobility of the oil and the low vertical permeability of the reservoir contribute to the predicted low (26\%) recovery efficiencies.",
    url = "https://doi.org/10.1144/petgeo.2.4.373",
    doi = "10.1144/petgeo.2.4.373",
    number = "4",
    pages = "373-380",
    volume = "2"
}

@inproceedings{simm19974d,
    author = "Simm, R. and Uden, R.H. and Burford, S. and Plummer, C. and Harrison, P. and Johnson, R.",
    title = "4D Seismic Modelling - Nelson Field, Central North Sea",
    year = "1997",
    booktitle = "59th EAGE Conference \& Exhibition",
    url = "https://doi.org/10.3997/2214-4609-pdb.131.gen1997\_b043",
    doi = "10.3997/2214-4609-pdb.131.gen1997\_b043"
}

Free hanging metal risers have become an important alternative to flexible risers for oil and gas field developments. These risers also have a potential benefit when used in high temperature and high-pressure applications. This paper presents a summary of the work performed to establish Steel Catenary Riser (SCR) concepts for two fields in North Sea. They are: Statfjord C, a gravity based concrete platform located on the Norwegian continental shelf in a water depth of approximately 145 m and Heidrun, with a concrete TLP at a water depth of 345 m. These developed configurations fulfil both the Ultimate Limit State (ULS) conditions and fatigue due to first order wave action and due to vortex induced vibrations. Also, as shown in this paper, the Fatigue Limit State (FLS) governs the global configuration of the SCR concept. In order to achieve a confident design, several design aspects have been studied in detail:First order wave loadingVortex Induced Vibration (VIV)Diffraction effects (from the large volume structure)Riser/Soil interactionFatigue capacity Introduction A number of research and development projects are currently evaluating the applicability of the SCR concept to floating production systems mainly in deep-water environments (e.g. Karunakaran et al. (1996), Hatton et al. (1998)). However, as shown in this paper, the SCR concept could be an attractive alternative also for tie-in of pipelines to fixed platform structures, like Statfjord C, see Figure 1. Even in the absence of top-end motions (as for floating production units), the design challenges for a SCR concept for this application are significant. Due to the relatively shallow water and quite severe wave and current environment, the riser is subject to large hydrodynamic loading causing extensive dynamic behavior. For the Heidrun TLP shown in Figure 2, the design challenge for the metal risers is due to the riser dynamics from wave loading and the platform motions. Furthermore, for this concept the diffraction effects proved to be a key factor for fatigue response. In this paper the developed SCR configurations for both these fields are discussed along with the key issues governing the design of such riser concepts. Figure 1 Statfjord C and riser geometry (Available in full paper) Figure 2 Heidru TLP (Avalaible in full paper)

@inproceedings{karunakaran1999steel,
    author = "Karunakaran, Daniel and Lund, Kjell M. and Nordsve, Nils T.",
    title = "Steel Catenary Riser Configurations for North Sea Field Developments",
    year = "1999",
    booktitle = "Offshore Technology Conference",
    abstract = "Free hanging metal risers have become an important alternative to flexible risers for oil and gas field developments. These risers also have a potential benefit when used in high temperature and high-pressure applications. This paper presents a summary of the work performed to establish Steel Catenary Riser (SCR) concepts for two fields in North Sea. They are: Statfjord C, a gravity based concrete platform located on the Norwegian continental shelf in a water depth of approximately 145 m and Heidrun, with a concrete TLP at a water depth of 345 m. These developed configurations fulfil both the Ultimate Limit State (ULS) conditions and fatigue due to first order wave action and due to vortex induced vibrations. Also, as shown in this paper, the Fatigue Limit State (FLS) governs the global configuration of the SCR concept. In order to achieve a confident design, several design aspects have been studied in detail:First order wave loadingVortex Induced Vibration (VIV)Diffraction effects (from the large volume structure)Riser/Soil interactionFatigue capacity Introduction A number of research and development projects are currently evaluating the applicability of the SCR concept to floating production systems mainly in deep-water environments (e.g. Karunakaran et al. (1996), Hatton et al. (1998)). However, as shown in this paper, the SCR concept could be an attractive alternative also for tie-in of pipelines to fixed platform structures, like Statfjord C, see Figure 1. Even in the absence of top-end motions (as for floating production units), the design challenges for a SCR concept for this application are significant. Due to the relatively shallow water and quite severe wave and current environment, the riser is subject to large hydrodynamic loading causing extensive dynamic behavior. For the Heidrun TLP shown in Figure 2, the design challenge for the metal risers is due to the riser dynamics from wave loading and the platform motions. Furthermore, for this concept the diffraction effects proved to be a key factor for fatigue response. In this paper the developed SCR configurations for both these fields are discussed along with the key issues governing the design of such riser concepts. Figure 1 Statfjord C and riser geometry (Available in full paper) Figure 2 Heidru TLP (Avalaible in full paper)",
    url = "https://doi.org/10.4043/10979-ms",
    doi = "10.4043/10979-ms"
}

@article{doi1011441354079310022,
    author = "Kilhams, Ben A. and Godfrey, S. and Hartley, A. and Huuse, M.",
    title = "An integrated 3D seismic, petrophysical and analogue core study of the Mid-Eocene Grid channel complex in the greater Nelson Field area, UK Central North Sea",
    year = "2011",
    journal = "Petroleum Geoscience",
    url = "https://www.semanticscholar.org/paper/86bf040d4d8e6ae807b7737277967411c105622b",
    doi = "10.1144/1354-079310-022",
    is_oa = "true",
    number = "2",
    pages = "127-142",
    semanticscholar_citation_count = "12",
    semanticscholar_id = "86bf040d4d8e6ae807b7737277967411c105622b",
    volume = "17"
}

The presence of hydrocarbon-bearing sandstones within the Eocene of the Forties area was first documented in 1985, when a Forties field (Paleocene) development well discovered the Brimmond field. Further hydrocarbons in the Eocene were discovered in the adjacent Maule field in 2009. Reservoir geometry derived from three-dimensional seismic data has provided evidence for both a depositional and a sand injectite origin for the Eocene sandstones. The Brimmond field is located in a deep-water channel complex that extends to the southeast, whereas the Maule field sandstones have the geometry of an injection sheet on the updip margin of the Brimmond channel system with a cone-shape feature emanating from the top of the Forties Sandstone Member (Paleocene). The geometry of the Eocene sandstones in the Maule field indicates that they are intrusive and originated by the fluidization and injection of sand during burial. From seismic and borehole data, it is unclear whether the sand that was injected to form the Maule reservoir was derived from depositional Eocene sandstones or from the underlying Forties Sandstone Member. These two alternatives are tested by comparing the heavy mineral and garnet geochemical characteristics of the injectite sandstones in the Maule field with the depositional sandstones of the Brimmond field and the Forties sandstones of the Forties field. The study revealed significant differences between the sandstones in the Forties field and those of the Maule and Brimmond fields), both in terms of heavy mineral and garnet geochemical data. The Brimmond-Maule and Forties sandstones therefore have different provenances and are genetically unrelated, indicating that the sandstones in the Maule field did not originate by the fluidization of Forties sandstones. By contrast, the provenance characteristics of the depositional Brimmond sandstones are closely comparable with sandstone intrusions in the Maule field. We conclude that the injectites in the Maule field formed by the fluidization of depositional Brimmond sandstones but do not exclude the important function of water from the huge underlying Forties Sandstone Member aquifer as the agent for developing the fluid supply and elevating pore pressure to fluidize and inject the Eocene sand. The study has demonstrated that heavy mineral provenance studies are an effective method of tracing the origin of injected sandstones, which are increasingly being recognized as an important hydrocarbon play.

@article{doi10130606141312191,
    author = "Morton, A. and McFadyen, S. and Hurst, A. and Pyle, J. and Rose, P.",
    title = "Constraining the origin of reservoirs formed by sandstone intrusions: Insights from heavy mineral studies of the Eocene in the Forties area, United Kingdom central North Sea",
    year = "2014",
    journal = "AAPG Bulletin",
    abstract = "The presence of hydrocarbon-bearing sandstones within the Eocene of the Forties area was first documented in 1985, when a Forties field (Paleocene) development well discovered the Brimmond field. Further hydrocarbons in the Eocene were discovered in the adjacent Maule field in 2009. Reservoir geometry derived from three-dimensional seismic data has provided evidence for both a depositional and a sand injectite origin for the Eocene sandstones. The Brimmond field is located in a deep-water channel complex that extends to the southeast, whereas the Maule field sandstones have the geometry of an injection sheet on the updip margin of the Brimmond channel system with a cone-shape feature emanating from the top of the Forties Sandstone Member (Paleocene). The geometry of the Eocene sandstones in the Maule field indicates that they are intrusive and originated by the fluidization and injection of sand during burial. From seismic and borehole data, it is unclear whether the sand that was injected to form the Maule reservoir was derived from depositional Eocene sandstones or from the underlying Forties Sandstone Member. These two alternatives are tested by comparing the heavy mineral and garnet geochemical characteristics of the injectite sandstones in the Maule field with the depositional sandstones of the Brimmond field and the Forties sandstones of the Forties field. The study revealed significant differences between the sandstones in the Forties field and those of the Maule and Brimmond fields), both in terms of heavy mineral and garnet geochemical data. The Brimmond-Maule and Forties sandstones therefore have different provenances and are genetically unrelated, indicating that the sandstones in the Maule field did not originate by the fluidization of Forties sandstones. By contrast, the provenance characteristics of the depositional Brimmond sandstones are closely comparable with sandstone intrusions in the Maule field. We conclude that the injectites in the Maule field formed by the fluidization of depositional Brimmond sandstones but do not exclude the important function of water from the huge underlying Forties Sandstone Member aquifer as the agent for developing the fluid supply and elevating pore pressure to fluidize and inject the Eocene sand. The study has demonstrated that heavy mineral provenance studies are an effective method of tracing the origin of injected sandstones, which are increasingly being recognized as an important hydrocarbon play.",
    url = "https://www.semanticscholar.org/paper/538242d29128c738455e27aa4efdcabe58b1322a",
    doi = "10.1306/06141312191",
    is_oa = "true",
    number = "3",
    pages = "545-561",
    semanticscholar_citation_count = "11",
    semanticscholar_id = "538242d29128c738455e27aa4efdcabe58b1322a",
    volume = "98"
}

Much of the future hydrocarbon exploration potential in the North Sea lies in locating stratigraphic traps and discrete reservoir intervals. This study assesses the potential for Lower Cretaceous reservoirs, with particular focus on the Norwegian Central Graben and methods to identify future prospects over a wider area. Seismic interpretation and well data reveal the structure and sedimentology of the study area. Although the region was isolated from a large hinterland in the Early Cretaceous, potential local sediment sources, sediment transport routes and areas with possible reservoir development are identified. The greater Mandal High area, where Lower Cretaceous shoreface deposits and submarine fan systems are postulated, is suggested for primary focus. Similar deposits may have developed around the other exposed highs in the region, although several were drowned towards the end of the Early Cretaceous. Detailed seismic and stratigraphic analysis will be necessary to identify individual reservoir units. Since comparable settings may have occurred in the adjacent South Viking Graben and Southern Permian Basin regions during the Early Cretaceous, further reservoir assessment is recommended for the North Sea in general.

@article{doi101144sp4693,
    author = "Zwaan, F.",
    title = "Lower Cretaceous reservoir development in the North Sea Central Graben, and potential analogue settings in the Southern Permian Basin and South Viking Graben",
    year = "2018",
    journal = "Special Publications",
    abstract = "Much of the future hydrocarbon exploration potential in the North Sea lies in locating stratigraphic traps and discrete reservoir intervals. This study assesses the potential for Lower Cretaceous reservoirs, with particular focus on the Norwegian Central Graben and methods to identify future prospects over a wider area. Seismic interpretation and well data reveal the structure and sedimentology of the study area. Although the region was isolated from a large hinterland in the Early Cretaceous, potential local sediment sources, sediment transport routes and areas with possible reservoir development are identified. The greater Mandal High area, where Lower Cretaceous shoreface deposits and submarine fan systems are postulated, is suggested for primary focus. Similar deposits may have developed around the other exposed highs in the region, although several were drowned towards the end of the Early Cretaceous. Detailed seismic and stratigraphic analysis will be necessary to identify individual reservoir units. Since comparable settings may have occurred in the adjacent South Viking Graben and Southern Permian Basin regions during the Early Cretaceous, further reservoir assessment is recommended for the North Sea in general.",
    url = "https://boris.unibe.ch/108305/7/Zwaan\%202018\_postprint.pdf",
    doi = "10.1144/SP469.3",
    is_oa = "true",
    number = "1",
    pages = "479-504",
    semanticscholar_citation_count = "8",
    semanticscholar_id = "c963bcda72a4f2853abf1d26a6f4cfe2c99d455c",
    volume = "469"
}

The high pressure – high temperature Culzean field, UK Central North Sea, contains lean gas condensate in the Triassic Joanne sandstones and the Middle Jurassic Pentland sandstones. A comprehensive gas analysis programme was installed as an integrated part of field development in order to monitor gas composition, distribution and origin in the reservoirs and overburden pre‐ production start‐up. Isotube OUT and isotube IN gas samples were collected. The isotube IN data show that some gas is recycled, including alkenes representing contamination from the degradation of mud additives; but concentrations are minor, and do not seem to affect the isotope values derived from the C2 and C3 isotube OUT gases significantly. 13C‐enriched methane derived from drill‐bit metamorphism is recorded in the isotube IN gas, but likewise in low concentrations. Gas data were also acquired from a Continuous Isotope Logging Tool (CILT) which measures real‐time gas concentrations and isotope values of C1–C3 each foot through the entire drilled section. The CILT thus provides a continuous trend of methane isotope values versus depth, and this trend is useful in identifying changes in gas composition. However, concerns related to CILT include: (i) C1–C3 stable carbon isotope detection limits for isotube OUT gas analyses are considerable lower than for CILT; due to the lower isotube gas concentrations required for measurement of C3 isotopes, isotubes are able to map a shallower vertical thermogenic gas migration front in the overburden. (ii) Discrepancies between isotube OUT and CILT isotope values may be significant and cannot be assigned to analytical uncertainty; by contrast, test gas and isotube OUT isotope values are comparable. Hence, CILT isotope values from specific depths cannot stand in isolation but must be complemented by isotube OUT isotope measurements.

@article{doi101111jpg12745,
    author = "Petersen, H. and Hillock, P. and Milner, S. and Pendlebury, M. and Scarlett, D.",
    title = "MONITORING GAS DISTRIBUTION AND ORIGIN IN THE CULZEAN FIELD, UK CENTRAL NORTH SEA, USING DATA FROM A CONTINUOUS ISOTOPE LOGGING TOOL AND ISOTUBE AND TEST SAMPLES",
    year = "2019",
    journal = "Journal of Petroleum Geology",
    abstract = "The high pressure – high temperature Culzean field, UK Central North Sea, contains lean gas condensate in the Triassic Joanne sandstones and the Middle Jurassic Pentland sandstones. A comprehensive gas analysis programme was installed as an integrated part of field development in order to monitor gas composition, distribution and origin in the reservoirs and overburden pre‐ production start‐up. Isotube OUT and isotube IN gas samples were collected. The isotube IN data show that some gas is recycled, including alkenes representing contamination from the degradation of mud additives; but concentrations are minor, and do not seem to affect the isotope values derived from the C2 and C3 isotube OUT gases significantly. 13C‐enriched methane derived from drill‐bit metamorphism is recorded in the isotube IN gas, but likewise in low concentrations. Gas data were also acquired from a Continuous Isotope Logging Tool (CILT) which measures real‐time gas concentrations and isotope values of C1–C3 each foot through the entire drilled section. The CILT thus provides a continuous trend of methane isotope values versus depth, and this trend is useful in identifying changes in gas composition. However, concerns related to CILT include: (i) C1–C3 stable carbon isotope detection limits for isotube OUT gas analyses are considerable lower than for CILT; due to the lower isotube gas concentrations required for measurement of C3 isotopes, isotubes are able to map a shallower vertical thermogenic gas migration front in the overburden. (ii) Discrepancies between isotube OUT and CILT isotope values may be significant and cannot be assigned to analytical uncertainty; by contrast, test gas and isotube OUT isotope values are comparable. Hence, CILT isotope values from specific depths cannot stand in isolation but must be complemented by isotube OUT isotope measurements.",
    url = "https://www.semanticscholar.org/paper/f4f208002e259d423658fe2d01d1460a1748b1a9",
    doi = "10.1111/jpg.12745",
    is_oa = "true",
    number = "4",
    pages = "435-449",
    semanticscholar_citation_count = "13",
    semanticscholar_id = "f4f208002e259d423658fe2d01d1460a1748b1a9",
    volume = "42"
}

ABSTRACT The Cenozoic of the North Sea is among the best-documented stratigraphical successions in the world, and multiple palynological events have been recognised for chronostratigraphical control across the region. The ever-increasing number of wells studied for hydrocarbon exploration and production results in the generation of new biostratigraphical data that constantly increase our palynological knowledge of the area. Here we describe two new dinoflagellate cyst species from an Lower Eocene (Ypresian) to Lower Oligocene (Rupelian) succession in Gannet Field (UK Central North Sea). These are Reticulatosphaera valdereticulata sp. nov., a short-lived Rupelian index taxon, and Alisocysta heilmannii sp. nov., previously informally known as Alisocysta sp. 2, which is an Ypresian marker widely used by biostratigraphers working the North Sea region. The development of a dense network of trabeculae connecting the processes distally allows Reticulatosphaera valdereticulata sp. nov. to be clearly distinguished from the closely similar Reticulatosphaera actinocoronata. The main diagnostic feature in Alisocysta heilmannii sp. nov. is the development of delicate penitabular septa. Both species show widespread palaeogeographical distribution across the North Sea region. We also document the diverse palynofloras in which the two new species are encountered and discuss biostratigraphical application and palaeoenvironmental settings.

@article{doi1010800191612220201819457,
    author = "Casas‐Gallego, Manuel and Gogin, I. and Vieira, M.",
    title = "Two New Dinoflagellate Cyst Species and Their Biostratigraphical Application in the Eocene and Oligocene of the North Sea",
    year = "2020",
    journal = "Palynology",
    abstract = "ABSTRACT The Cenozoic of the North Sea is among the best-documented stratigraphical successions in the world, and multiple palynological events have been recognised for chronostratigraphical control across the region. The ever-increasing number of wells studied for hydrocarbon exploration and production results in the generation of new biostratigraphical data that constantly increase our palynological knowledge of the area. Here we describe two new dinoflagellate cyst species from an Lower Eocene (Ypresian) to Lower Oligocene (Rupelian) succession in Gannet Field (UK Central North Sea). These are Reticulatosphaera valdereticulata sp. nov., a short-lived Rupelian index taxon, and Alisocysta heilmannii sp. nov., previously informally known as Alisocysta sp. 2, which is an Ypresian marker widely used by biostratigraphers working the North Sea region. The development of a dense network of trabeculae connecting the processes distally allows Reticulatosphaera valdereticulata sp. nov. to be clearly distinguished from the closely similar Reticulatosphaera actinocoronata. The main diagnostic feature in Alisocysta heilmannii sp. nov. is the development of delicate penitabular septa. Both species show widespread palaeogeographical distribution across the North Sea region. We also document the diverse palynofloras in which the two new species are encountered and discuss biostratigraphical application and palaeoenvironmental settings.",
    url = "https://www.semanticscholar.org/paper/5758ac835a5d7d8aba43283cd5fa34a89859011c",
    doi = "10.1080/01916122.2020.1819457",
    is_oa = "true",
    number = "2",
    pages = "337-349",
    semanticscholar_citation_count = "7",
    semanticscholar_id = "5758ac835a5d7d8aba43283cd5fa34a89859011c",
    volume = "45"
}

Abstract The Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer. The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy. The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.

@article{doi101144m52201822,
    author = "Hale, M. and Laird, R. and Gavnholt, J. and van Bergen, P. V.",
    title = "The Pierce Field, Blocks 23/22a and 23/27, UK North Sea",
    year = "2020",
    journal = "memoirs",
    abstract = "Abstract The Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer. The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy. The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.",
    url = "https://www.semanticscholar.org/paper/c7bdec14b3152826889ff29971032157fffafd4f",
    doi = "10.1144/M52-2018-22",
    is_oa = "true",
    number = "1",
    pages = "550-559",
    semanticscholar_citation_count = "1",
    semanticscholar_id = "c7bdec14b3152826889ff29971032157fffafd4f",
    volume = "52"
}

Abstract The Alba Field is a relatively heavy oil accumulation lying in an Eocene deep-water channel complex in Block 16/26a of the Central North Sea. With an estimated 880 MMbbl in place, the reservoir is characterized by thick, high net/gross sands with excellent reservoir properties and rock physics favourable for seismic property detection. The field has been developed by horizontal production wells, with pressure support provided by seawater injectors. After 24 years of production, more than 427 MMbbl have been recovered. Over the course of the development, the results of development drilling and improved reservoir imaging from seismic have revealed greater reservoir complexity than anticipated at sanction. The highly irregular reservoir geometry is likely to reflect the internal stacking patterns of channel elements within the channel complex that are locally overprinted by post-depositional remobilization. This increased reservoir complexity has required more wells to effectively drain the expected volumes. Despite this, recovery has exceeded estimates from the initial field development plan, reflecting an extremely efficient waterflood. 4D seismic spectacularly images extensive sweep away from injectors and excellent reservoir connectivity. Throughout the development, the application of seismic technologies has been a key enabler for effective reservoir management and, looking forward, maximizing value.

@article{doi101144m52201846,
    author = "Moore, I. and Archer, J. and Peavot, David",
    title = "The Alba Field, Block 16/26a, UK North Sea",
    year = "2020",
    journal = "memoirs",
    abstract = "Abstract The Alba Field is a relatively heavy oil accumulation lying in an Eocene deep-water channel complex in Block 16/26a of the Central North Sea. With an estimated 880 MMbbl in place, the reservoir is characterized by thick, high net/gross sands with excellent reservoir properties and rock physics favourable for seismic property detection. The field has been developed by horizontal production wells, with pressure support provided by seawater injectors. After 24 years of production, more than 427 MMbbl have been recovered. Over the course of the development, the results of development drilling and improved reservoir imaging from seismic have revealed greater reservoir complexity than anticipated at sanction. The highly irregular reservoir geometry is likely to reflect the internal stacking patterns of channel elements within the channel complex that are locally overprinted by post-depositional remobilization. This increased reservoir complexity has required more wells to effectively drain the expected volumes. Despite this, recovery has exceeded estimates from the initial field development plan, reflecting an extremely efficient waterflood. 4D seismic spectacularly images extensive sweep away from injectors and excellent reservoir connectivity. Throughout the development, the application of seismic technologies has been a key enabler for effective reservoir management and, looking forward, maximizing value.",
    url = "https://www.semanticscholar.org/paper/6e9f3eeea53b4f5ef97a09529843aeeb34331b4b",
    doi = "10.1144/M52-2018-46",
    is_oa = "true",
    number = "1",
    pages = "637-650",
    semanticscholar_citation_count = "3",
    semanticscholar_id = "6e9f3eeea53b4f5ef97a09529843aeeb34331b4b",
    volume = "52"
}

Abstract The Chestnut oilfield was discovered in 1986 and lies within Block 22/2a, Licence P354, of the UK Central North Sea. The field is approximately 7 km south of the Britannia gas condensate field and 8 km SE of the Alba oilfield on the southern edge of the Witch Ground Graben. The field comprises injected Lower Eocene Nauchlan sandstone encased within Horda Formation shales. The Chestnut Field began production in 2008 through the Hummingbird floating production vessel by means of two producer wells and one injector well. The complex reservoir geometries present seismic imaging challenges, and production data have indicated a larger connected volume than mapped from seismic data. In 2017, an infill producer well was drilled to arrest production decline. This well proved the presence and connectivity of sandstone beyond the field interior and increased confidence in using seismic data for predicting the injectite reservoir distribution.

@article{doi101144m52201881,
    author = "van Oorschot, R. and Fletcher, A. and Basford, H. and Stuart, A.",
    title = "The Chestnut Field, Block 22/2a, UK North Sea",
    year = "2020",
    journal = "memoirs",
    abstract = "Abstract The Chestnut oilfield was discovered in 1986 and lies within Block 22/2a, Licence P354, of the UK Central North Sea. The field is approximately 7 km south of the Britannia gas condensate field and 8 km SE of the Alba oilfield on the southern edge of the Witch Ground Graben. The field comprises injected Lower Eocene Nauchlan sandstone encased within Horda Formation shales. The Chestnut Field began production in 2008 through the Hummingbird floating production vessel by means of two producer wells and one injector well. The complex reservoir geometries present seismic imaging challenges, and production data have indicated a larger connected volume than mapped from seismic data. In 2017, an infill producer well was drilled to arrest production decline. This well proved the presence and connectivity of sandstone beyond the field interior and increased confidence in using seismic data for predicting the injectite reservoir distribution.",
    url = "https://www.semanticscholar.org/paper/4bf224784dbf07897a1e9782836614a70d1b67fe",
    doi = "10.1144/M52-2018-81",
    is_oa = "true",
    number = "1",
    pages = "413-423",
    semanticscholar_citation_count = "3",
    semanticscholar_id = "4bf224784dbf07897a1e9782836614a70d1b67fe",
    volume = "52"
}

Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO2 storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C3–C5, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C1 (methane) and partly C2 (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane‐derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe‐out zones (gas chimneys), bright zones (gas‐charged sediments or MDACs), and depressions (pockmarks). In general, potential CO2 storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO2 storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (palaeo‐) leakage phenomena and provide support for seal integrity evaluation at local to regional scales.

@article{doi101111jpg12830,
    author = "Petersen, H. and Smit, F.",
    title = "APPLICATION OF MUD GAS DATA AND LEAKAGE PHENOMENA TO EVALUATE SEAL INTEGRITY OF POTENTIAL CO2 STORAGE SITES: A STUDY OF CHALK STRUCTURES IN THE DANISH CENTRAL GRABEN, NORTH SEA",
    year = "2022",
    journal = "Journal of Petroleum Geology",
    abstract = "Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO2 storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C3–C5, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C1 (methane) and partly C2 (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane‐derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe‐out zones (gas chimneys), bright zones (gas‐charged sediments or MDACs), and depressions (pockmarks). In general, potential CO2 storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO2 storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (palaeo‐) leakage phenomena and provide support for seal integrity evaluation at local to regional scales.",
    url = "https://www.semanticscholar.org/paper/e53510ae4a85f99f557a7b2136b51fb1ab30a729",
    doi = "10.1111/jpg.12830",
    is_oa = "true",
    number = "1",
    pages = "47-75",
    semanticscholar_citation_count = "6",
    semanticscholar_id = "e53510ae4a85f99f557a7b2136b51fb1ab30a729",
    volume = "46"
}

The Eocene‐Oligocene transition (EOT) (∼34 Ma) is marked by the rapid development of a semi‐permanent Antarctic ice‐sheet, as indicated by ice‐rafted debris and a 1–1.5‰ increase in deep sea δ18O. Proxy reconstructions indicate a drop in atmospheric CO2 and global cooling. How these changes affected surface ocean temperatures in the North Atlantic and ocean water stratification remains poorly constrained. In this study, we apply clumped‐isotope thermometry to well‐preserved planktonic foraminifera, that are associated with lower mixed‐layer to subthermocline dwelling depths from the drift sediments at international ocean discovery program Site 1411, Newfoundland, across four intervals bracketing the EOT. The thermocline/lower mixed‐layer dwelling foraminifera record a cooling of 1.9 ± 3.5 K (mean ± 95% CI) across the EOT. While the cooling amplitude is similar to previous sea surface temperature (SST) reconstructions, absolute temperatures (Eocene 20.0 ± 2.9°C, Oligocene 18.0 ± 2.2°C) appear colder than previous organic proxy reconstructions for the northernmost Atlantic extrapolated to this location. We discuss seasonal bias, recording depth, and appropriate consideration of paleolatitudes, all of which complicate the comparison between SST reconstructions and model output. Our subthermocline dwelling foraminifera record a larger cooling across the EOT (Eocene 19.0 ± 3.5°C, Oligocene 13.0 ± 3.2°C, cooling of 5.5 ± 4.6 K) than foraminifera from the thermocline/lower mixed‐layer, consistent with global cooling and an increase in ocean stratification which may be related to the onset or intensification of the Atlantic meridional overturning circulation.

@article{doi1010292023pa004809,
    author = "Kocken, I. and Nooteboom, Peter D. and Veen, K. and Coxall, H. and Müller, I. A. and Meckler, A. and Ziegler, Martin",
    title = "North Atlantic Temperature Change Across the Eocene‐Oligocene Transition From Clumped Isotopes",
    year = "2024",
    journal = "Paleoceanography and Paleoclimatology",
    abstract = "The Eocene‐Oligocene transition (EOT) (∼34 Ma) is marked by the rapid development of a semi‐permanent Antarctic ice‐sheet, as indicated by ice‐rafted debris and a 1–1.5‰ increase in deep sea δ18O. Proxy reconstructions indicate a drop in atmospheric CO2 and global cooling. How these changes affected surface ocean temperatures in the North Atlantic and ocean water stratification remains poorly constrained. In this study, we apply clumped‐isotope thermometry to well‐preserved planktonic foraminifera, that are associated with lower mixed‐layer to subthermocline dwelling depths from the drift sediments at international ocean discovery program Site 1411, Newfoundland, across four intervals bracketing the EOT. The thermocline/lower mixed‐layer dwelling foraminifera record a cooling of 1.9 ± 3.5 K (mean ± 95\% CI) across the EOT. While the cooling amplitude is similar to previous sea surface temperature (SST) reconstructions, absolute temperatures (Eocene 20.0 ± 2.9°C, Oligocene 18.0 ± 2.2°C) appear colder than previous organic proxy reconstructions for the northernmost Atlantic extrapolated to this location. We discuss seasonal bias, recording depth, and appropriate consideration of paleolatitudes, all of which complicate the comparison between SST reconstructions and model output. Our subthermocline dwelling foraminifera record a larger cooling across the EOT (Eocene 19.0 ± 3.5°C, Oligocene 13.0 ± 3.2°C, cooling of 5.5 ± 4.6 K) than foraminifera from the thermocline/lower mixed‐layer, consistent with global cooling and an increase in ocean stratification which may be related to the onset or intensification of the Atlantic meridional overturning circulation.",
    url = "https://onlinelibrary.wiley.com/doi/pdfdirect/10.1029/2023PA004809",
    doi = "10.1029/2023PA004809",
    is_oa = "true",
    number = "3",
    semanticscholar_citation_count = "3",
    semanticscholar_id = "795487d092c25a88e3b7f72bd5b0e6521aa9056e",
    volume = "39"
}

@incollection{kingNonethe,
    author = "King, C.",
    title = "The North Sea Basin: Eocene",
    year = "None",
    booktitle = "A revised correlation of Tertiary rocks in the British Isles and adjacent areas of NW Europe",
    url = "https://doi.org/10.1144/sr27.11",
    doi = "10.1144/sr27.11",
    pages = "155-228"
}