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

2020 ◽  
Vol 52 (1) ◽  
pp. 436-446 ◽  
Author(s):  
A. D. Irving ◽  
K. F. Raphael ◽  
P. M. Rennison ◽  
R. Lewis ◽  
C. D. Cruickshank ◽  
...  
Keyword(s):  
Initial Pressure ◽  
Upper Jurassic ◽  
Central Process ◽  
Fault Block ◽  
High Pressure High Temperature ◽  
Temperature Development ◽  
Production Wells ◽  
Cumulative Production ◽  
The Uk ◽  
Block Structures

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

2020 ◽  
Vol 52 (1) ◽  
pp. 875-885 ◽  
Author(s):  
I. N. Stephens ◽  
S. Small ◽  
P. H. Wood
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
The North ◽  
Recoverable Reserves ◽  
Fault Block ◽  
Production Wells ◽  
The North Sea ◽  
The Uk ◽  
Clay Formation

AbstractThe 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 Dunlin Field, Blocks 211/23a and 211/24a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 95-102 ◽  
Author(s):  
A. Baumann ◽  
B. O'Cathain
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Oil Accumulation ◽  
Western Margin ◽  
Shetland Islands ◽  
Fault Block ◽  
Delta System ◽  
Cumulative Production

AbstractThe Dunlin Oilfield is located in the East Shetland Basin, 160 km northeast of the Shetland Islands. It lies in UK Blocks 211/23a and 211/24a in about 500 ft of water. The field was discovered in June 1973 by well 211/23-1. The oil accumulation is trapped, in a north-south oriented, tilted fault block at the western margin of the Viking Graben, at a depth of about 8500 ft TVSS. The reservoir is contained in the formations of the Middle Jurassic Brent Group. In the Dunlin area they form a 450 ft thick sequence of sands and intercalated minor shales, which has been deposited by a shore face and delta system prograding northwards across the Viking Graben. The seal is formed by the shales of the Middle/Upper Jurassic Heather Formation. Reservoir properties of the Brent sands are fair to good with porosities of up to 30% and average permeabilities in the range from 10 to 4000 md. Development of the field is carried out from a single platform, from which production started in 1978. To date 40 development wells have been drilled and the total cumulative production amounts to 282 MMBBL of an ultimate recovery of 363 MMBBL.

The Erskine Field, Block 23/26b, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 447-453 ◽  
Author(s):  
I. Robertson
Keyword(s):  
Free Water ◽  
Initial Pressure ◽  
Development Planning ◽  
Water Production ◽  
Pressure Data ◽  
Sand Production ◽  
Wax Deposition ◽  
Field Development ◽  
High Pressure High Temperature ◽  
The Uk

AbstractThe Erskine high-pressure–high-temperature gas condensate field was the first such field developed in the UK Continental Shelf. Since production started in 1997, the field has produced over 350 bcf of gas and 70 MMbbl of condensate. The reservoir pressure has depleted from an initial pressure of 960 bar (13 920 psi) down to 140–400 bar (2030–5800 psi), resulting in some compaction and sand production in some of the wells. Free water production has led to the formation of wellbore scale, which has required interventions to remove.The reservoirs are sandstones of the Jurassic Puffin, Pentland and Heather formations. Estimates of hydrocarbons in place made using production and pressure data compare favourably with the initial estimates made during field development planning, although the Pentland Formation volume is some 20% below the sanction estimate.Several major field outages have occurred, such as a condensate fire in 2010 and a blockage of the multiphase export pipeline in 2007. In addition, the field has experienced flow assurance problems related to scale and wax deposition. A new pipeline section was installed in 2018 to bypass a full pipeline blockage which occurred due to wax deposition.

The Magnus Field, Block 211/7a, 12a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 153-157 ◽  
Author(s):  
M. Shepherd
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Hydrocarbon Source Rock ◽  
Submarine Fan ◽  
Oil Accumulation ◽  
The North ◽  
Fault Block ◽  
The North Sea ◽  
The Uk ◽  
Clay Formation

abstractMagnus is the most northerly producing field in the UK sector of the North Sea. The oil accumulation occurs within sandstones of an Upper Jurassic submarine fan sequence. The combination trap style consists of reservoir truncation by unconformity at the crest of the easterly dipping fault block structure and a stratigraphic pinchout element at the northern and southern limits of the sand rich fan. The reservoir is enveloped by the likely hydrocarbon source rock, the organic rich mudstones of the Kimmeridge Clay Formation.

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

1991 ◽  
Vol 14 (1) ◽  
pp. 347-352 ◽  
Author(s):  
P. L. Cutts
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Injection Wells ◽  
The North ◽  
Clay Shales ◽  
Gravity Flows ◽  
Production Wells ◽  
The Uk

AbstractThe Maureen 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 late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

The Murchison Field, Block 211/19a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 165-173
Author(s):  
John Warrender
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Oil Field ◽  
Medium Size ◽  
Fault Block ◽  
International Boundary ◽  
Northern North Sea ◽  
The Uk

AbstractThe Murchison oil field forms part of the Brent oil province in the East Shetland Basin, northern North Sea. The field, which straddles the UK-Norway international boundary, was discovered in 1975 and began production with Conoco (UK) Ltd as Operator, in 1980. Like many oil accumulations in the East Shetland Basin the trap consists of a northwesterly dipping rotated fault block of Jurassic-Triassic age sourced and sealed by unconformable Upper Jurassic shales. The productive reservoir consists of Middle Jurassic Brent Group sandstones which represent the south to north progradation of a wave/tide influenced delta system. The Brent Group on Murchison has an average thickness of 425 ft with average porosities of 22% and permeabilities in the 500-1000 md range in producing zones. The maximum hydrocarbon column thickness is approximately 600 ft. The oil is undersaturated and no gas cap is present. Recoverable reserves are 340 MMBBL from a total oil in place figure of 790 MMBBL. Oil production which is via a single steel jacket platform peaked at 127 000 BOPD in 1983 and currently averages 45 000 BOPD. Economic field life is expected to be at least 20 years.The Murchison Field is located in the East Shetland Basin, northern North Sea at approximate latitude 61° 23' N, longitude 1° 43.5' E, 120 miles northeast of the Shetland Islands (Fig. 1). The field straddles the UK-Norway international boundary with the greater portion in the UK Block 21 l/19a and the lesser portion in Norway Block 33/9. Water depth is -512 ft BMSL. In the context of the North Sea the field is of medium size with an areal closure of approximately 7 square miles and contains 790 million barrels of oil in place. The productive reservoir consists of coastal deltaic sandstones of the Middle Jurassic Brent Group which lie between the marine shales of the Lower Jurassic Dunlin Group and the marine, organic-rich shales of the Upper Jurassic Humber Group. The trap is structural comprising a single, northwesterly dipping rotated fault block which has been sourced and sealed by the overlying Upper Jurassic shales. The field is named after the Scottish geologist Sir Roderick Impey Murchison (1792-1871), who is best known for his contribution to Palaeozoic stratigraphy.

The Buchan Field, Blocks 20/5a and 21/1a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 253-259 ◽  
Author(s):  
C. W. Edwards
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Hydrocarbon Migration ◽  
Red Sandstone ◽  
Recoverable Reserves ◽  
Fault Block ◽  
Southern Side ◽  
The Witch ◽  
The Uk ◽  
Sandstone Facies

AbstractThe Buchan Oilfield is located in Blocks 21/la and 20/5a of the UK North Sea, on the southern side of the Witch Ground Graben. The Buchan structure is a complex tilted and dissected fault block formed during Jurassic extension and rifting. The Upper Devonian-Carboniferous reservoir is composed of fluvial Old Red Sandstone facies sandstones sealed by Lower Cretaceous mudstones and contains a 585m (1919 ft) thick oil column. Poor matrix porosities and permeabilities are enhanced by a pervasive fracture system, although faulting in the reservoir restricts communication between several of the nine producing wells. Hydrocarbon migration has occurred from a mature Upper Jurassic source rock north of the field into the structure across the flank faults. Production of the highly under-saturated oil is by depletion drive with some aquifer sweep to a floating production facility and onward transmission to the Forties Field by pipeline. Production commenced in 1981 and original recoverable reserves are estimated at 90 MMBBL of which 71.5 MMBBL have already been produced.

The Thistle Field, Blocks 211/18a and 211/19, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 199-207
Author(s):  
R. R. Williams ◽  
A. D. Milne
Keyword(s):  
Normal Faults ◽  
Injection Wells ◽  
Western Margin ◽  
The North ◽  
Fault Block ◽  
Production Platform ◽  
Production Wells ◽  
Cumulative Production ◽  
Oil Company ◽  
Gas Lift

AbstractThe Thistle Oilfield is located on the western margin of the North Viking Graben in UK Blocks 21l/18a and 211/19. The field was discovered in 1973 by the Halibut Group, operated by the Signal Oil Company. The discovery well was drilled in 1973 and the field was declared commerical before completion of the first two appraisal wells. The extension of the field into Block 211/19 was confirmed by well 211/19-1 drilled in 1974 and the field was subsequently unitized.The Middle Jurassic Brent Group forms the oil-bearing reservoir sequence. The structure is an easterly dipping, rotated fault block divided into five main compartments by N-S normal faults and E-W cross faults. A 60 slot drilling and production platform was installed in 1976 and production began in February 1978. It is now connected by pipeline to Sullom Voe and production through this link commenced in late 1978. Due to only limited aquifer support, injection wells have been drilled on the east flank of the field, in order to maintain reservoir pressure. In addition, several wells in partly isolated fault blocks are produced by gas lift completions. The current STOIIP is estimated at 794 MMBBL of which 396 MMBBL will ultimately be recovered. Cumulative production to the end of 1988 was 334 MMBBL from 34 production wells, with support from 13 injection wells.

The Culzean Field, Block 22/25a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 424-435 ◽  
Author(s):  
Jeppe Nygaard ◽  
Michael Caulfield ◽  
Robert Gooder ◽  
Duncan Chedburn
Keyword(s):  
High Pressure ◽  
Initial Conditions ◽  
Central Area ◽  
Gas Condensate ◽  
Central Process ◽  
Field Development ◽  
Fault Block ◽  
High Pressure High Temperature ◽  
Start Up ◽  
Process Platform

AbstractThe Culzean Field is situated 240 km east of Aberdeen in Block 22/25a. The field was discovered in 2008 by well 22/25a-9Z targeting a tilted fault block, encountering lean-gas condensate in the fluvial Triassic Skagerrak (Joanne Sandstone Member) and the Jurassic Pentland formations. The field is high-pressure–high-temperature (HPHT) with initial conditions of 936 Bar (13 575 psi), 176°C (348°F) and charged with a lean-gas condensate. Development of the field was sanctioned in 2015 and is the latest UK HPHT field to be developed with start-up in mid-2019. The field development plan comprises production from six development wells drilled from a wellhead platform with bridge connections to a central process platform with accommodation on an additional bridge-linked utilities and living quarters platform. Gas is exported to shore via the Central Area Transmission System pipeline and produced condensate is exported via the floating storage and offloading vessel ‘Ailsa’. Production is expected to reach a plateau production rate in the order of 100 000 boepd with an overall recovery of up to 300 MMboe.

The geosolitonic concept of high output hydrocarbon deposits formation

2021 ◽  
pp. 13-22
Author(s):  
R. M. Bembel ◽  
S. R. Bembel ◽  
M. I. Zaboeva ◽  
E. E. Levitina
Keyword(s):  
Western Siberia ◽  
Oil And Gas ◽  
Chemical Elements ◽  
Seismic Exploration ◽  
Oil And Gas Fields ◽  
Recoverable Reserves ◽  
Production Wells ◽  
Cumulative Production ◽  
Gas Fields ◽  
Hydrocarbon Deposits

Based on the well-known results of studies of the ether-geosoliton concept of the growing Earth, the article presents the conclusions that made it possible to propose a model of thermonuclear synthesis of chemical elements that form renewable reserves of developed oil and gas fields. It was revealed that local zones of abnormally high production rates of production wells and, accordingly, large cumulative production at developed fields in Western Siberia are due to the restoration of recoverable reserves due to geosoliton degassing. Therefore, when interpreting the results of geological and geophysical studies, it is necessary to pay attention to the identified geosoliton degassing channels, since in the works of R. M. Bembel and others found that they contributed to the formation of a number of hydrocarbon deposits in Western Siberia. When interpreting the results of geological-geophysical and physicochemical studies of the fields being developed, it is recommended to study the data of the ring high-resolution seismic exploration technology in order to identify unique areas of renewable reserves, which can significantly increase the component yield of hydrocarbon deposits.

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