The Hamilton and Hamilton North Gas Fields, Block 110/13a, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 77-86 ◽  
Author(s):  
A. Yaliz ◽  
P. Taylor
Keyword(s):  
Gas Production ◽  
Irish Sea ◽  
Hydrocarbon Generation ◽  
High Porosity ◽  
Water Contact ◽  
The North ◽  
Depositional Processes ◽  
Sandstone Formation ◽  
Two Phases ◽  
Water Cut

AbstractThe Hamilton and Hamilton North Fields are located in Block 110/13a in the East Irish Sea, and contain 627 BCF and 230 BCF GIIP, respectively. First gas was produced from the Hamilton North Field in December 1995. The fields are being developed with four producers in the Hamilton Field and three in the Hamilton North Field. The Hamilton Field structure consists of a N-S trending horst block with dip closure to the north and south, while the Hamilton North structure is defined by major faults to the north and west with dip closure to the east and south. The gas is trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprises high porosity aeolian and fluvial sandstones. Depth to reservoir is shallow (2300-2600 ft) with the gas-water contact being at 2910 ft in the Hamilton Field and 3166 ft in the Hamilton North Field. Reservoir quality is principally controlled by primary depositional processes and no significant diagenetic effects are observed. The hydrocarbon filling history was complex, with at least two phases of hydrocarbon generation. Hamilton North gas is sweet whereas the Hamilton gas contains up to 11OOppm H2S, which is removed during processing at the Douglas complex and at the Point of Ayr gas terminal. Cumulative gas production to May 1999 was 180 BCF and no water-cut has been observed to date.

The Douglas Oil Fields, Block 110/13b, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 61-75 ◽  
Author(s):  
A. Yaliz ◽  
N. McKim
Keyword(s):  
Sea Water ◽  
Water Injection ◽  
Oil Field ◽  
Irish Sea ◽  
High Porosity ◽  
Injection Wells ◽  
Depositional Processes ◽  
Sandstone Formation ◽  
Two Phases ◽  
And Migration

AbstractThe Douglas Field, on stream in February 1996, is the first oil field to be developed in the East Irish Sea Basin, with an estimated STOIIP of 202 MMBBL. The field structure consists of three tilted fault blocks formed during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil is trapped in the Triassic Ormskirk Sandstone Formation, which comprises moderate to high porosity aeolian and fluvial sandstones. The reservoir depth is shallow (2140 ft) with a maximum oil column of 375 ft. The reservoir can be divided into several laterally extensive units based on vertical facies variations. The reservoir quality is principally controlled by primary depositional processes, and authigenic clay minerals are not important. However, bitumen is formed extensively in specific areas of the field causing significant permeability reduction. The hydrocarbon filling history of the field was complex, with the occurrence of at least two phases of oil generation and migration. The field contains a relatively 'dead' oil with a low GOR (170scf/bbl). Pressure maintenance is achieved through sea water injection, and to date ten production and six injection wells have been drilled. The crude is light (44° API) and contains high levels of H2S (0.5mol%) and mercaptans, which are removed during processing offshore.

The Lennox Field, Blocks 110/14c and 110/15a, UK East Irish Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 320-333 ◽  
Author(s):  
J. Bunce
Keyword(s):  
Initial Conditions ◽  
Oil Production ◽  
Gas Production ◽  
Irish Sea ◽  
Second Phase ◽  
Injection Wells ◽  
Field Development ◽  
Production Wells ◽  
Sandstone Formation ◽  
Two Phases

AbstractThe Lennox Field is a saturated oilfield with a significant primary gas cap at initial conditions. Located in the East Irish Sea withincBlocks 110/14c and 110/15a, the field was discovered in 1992. First oil was achieved in February 1996. Lennox is a rollover anticline structure. The Triassic Ormskirk Sandstone Formation reservoir comprises good-quality aeolian and fluvial sandstones with typicalcporosities of 11–21%. The gas column reaches a height of c. 850 ft and overlays a 143 ft oil column. Oil initially-in-place is estimated to be 202 MMbbl, whilst total gas initially-in-place is 521 bcf. The field has been developed by a wellhead platform tied-back to the neighbouring Douglas Complex. The field development has been split into two phases: the first phase focused on oil production and involved the drilling of 12 horizontal and multilateral production wells and two gas injection wells. Oil production ceased in 2012 with total produced volumes of 103 MMbbl. The second phase comprised the gas cap blowdown, and the optimization of the existing well stock for gas production. Eni UK acquired the operatorship of the field in April 2014 and has focused on maximizing and accelerating gas production from the field.

The Lennox Oil and Gas Field, Block 110/15, East Irish Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 87-96 ◽  
Author(s):  
A. Yaliz ◽  
T. Chapman
Keyword(s):  
Oil And Gas ◽  
Hanging Wall ◽  
Gas Production ◽  
Oil Field ◽  
Irish Sea ◽  
High Porosity ◽  
Gas Field ◽  
Blow Down ◽  
Depositional Processes ◽  
Oil Rim

AbstractThe Lennox Field, located in blocks 110/15 and 110/14, was the second oil field to be developed in the East Irish Sea Basin. It contains 184 MMBBL of oil in-place within a 143 ft thick oil rim overlain by a large gas cap up to 750 ft thick. The GIIP is estimated to be 497 BCF. The field came on stream in February 1996, and it is now being developed with seven horizontal oil producers, including two multi-lateral wells and two crestal gas injectors. Production from the field can be divided into two distinct phases; the oil rim development phase, and the gas cap blow-down phase. The latter phase is currently anticipated to commence in 2004. The field structure consists of a roll-over anticline formed in the hanging wall of the Formby Point Fault during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil and gas are trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprise high porosity aeolian and fluvial sandstones occurring at a shallow depth (c. 2500 ft) with a maximum gas column of 750 ft above an oil rim of 143 ft. The reservoir quality is principally controlled by primary depositional processes as no significant adverse diagenetic effects are observed. The hydrocarbon filling history was complex, with at least three phases of oil and gas generation. The field contains a light, saturated oil (45° API) with a GOR of 650 SCF/BBL. The crude contains high levels of H2S (0.1 mol%) and mercaptans (450 ppm), which are removed during processing at the Douglas complex. Water cut from the field is currently around 2-5%, and no free gas production has been observed to date. Gas production from Lennox is anticipated to start in 2004.

The Elswick Field, Bowland Basin, UK Onshore

2020 ◽  
Vol 52 (1) ◽  
pp. 62-73 ◽  
Author(s):  
Mathew Hampson ◽  
Heather Martin ◽  
Lucy Craddock ◽  
Thomas Wood ◽  
Ellie Rylands
Keyword(s):  
Electricity Generation ◽  
Alluvial Fan ◽  
Reservoir Quality ◽  
Gas Field ◽  
Water Contact ◽  
Depositional Processes ◽  
Well Field ◽  
Domal Structure ◽  
Single Well ◽  
Sandstone Formation

AbstractThe Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.

The Rhyl Field, Block 113/27b, UK East Irish Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 334-345 ◽  
Author(s):  
J. A. Patroni Zavala ◽  
M. Taylor ◽  
C. J. Tiltman ◽  
N. G. Sime
Keyword(s):  
Material Balance ◽  
Irish Sea ◽  
Reservoir Properties ◽  
Water Contact ◽  
Southern Boundary ◽  
History Of ◽  
Sandstone Formation ◽  
Facies Types ◽  
Gas Fields ◽  
Diagenetic History

AbstractThe Rhyl Field is located in the offshore East Irish Sea Basin, approximately 30 km to the west of Barrow-in-Furness. Rhyl is one of the producing gas fields forming the Morecambe Hub development, operated by Spirit Energy. The Rhyl reservoir is the Ormskirk Sandstone Formation of Triassic age which regionally comprises four depositional facies types: aeolian, fluvial, sandflat and playa. The depositional system provides excellent reservoir properties that are impacted by a diagenetic history of authigenic illitization and quartz overgrowths. The northern boundary of the field is located underneath the Fleetwood Dyke Complex, resulting in significant imaging and depth-conversion uncertainty. This has been addressed by dyke mapping and manual depth corrections to seismic processing. The trapping mechanism at the southern boundary of the field is also unclear; the dip-closed structural spill point as mapped at the southern boundary appears shallower than the log-derived gas–water contact. Rhyl gas contains a significant inert content: 37% CO2 and 7% N2. The field's production rate has been limited to approximately 40 MMscfgd by the CO2 processing limit of the onshore gas terminal. Material balance studies have yielded a satisfactory understanding of connected gas in place, recoverable reserves and dynamic field behaviour.

The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 871-880 ◽  
Author(s):  
Hugh Riches
Keyword(s):  
New Technology ◽  
Major Change ◽  
Gas Production ◽  
Seismic Survey ◽  
Daily Production ◽  
The North ◽  
Carbonaceous Shales ◽  
Sandstone Formation ◽  
And Migration ◽  
The Phoenix

AbstractFirst production from the Viking Fields began in 1972 and at its peak a total of 13 platforms produced at rates up to 950 MMSCF/D from 20 wells. This supplied around 10% of the United Kingdom's natural gas requirements, 27 years on, that rate had declined to approximately 40 MMSCF/D. However following an extremely successful infield drilling programme in the mid 1990s, significant volumes of new gas have been discovered and new technology has facilitated the development of accumulations previously considered non-commercial. This has led to three new developments within the Viking area: the Vampire Field on the eastern margin; Kx to the south of the Philips' Alison Field; and four previously non-producing fields, captured within the Phoenix Development.The major change since Morgan (1991) has primarily been the re-negotiation of the gas sales contract and the removal of the Gas Levy in 1992. This provided favourable marketing conditions for the development of additional Viking gas production and initiated an appraisal programme for remaining reserves. This programme, which will be the focus of this paper, began with the acquisition of a 3D seismic survey in 1993 and has concluded in the development of the Viking Extensions in 1998, now known as the Phoenix Development.The Leman Sandstone Formation forms the reservoir and consists of aeolian and fluvial sandstones, which are interbedded in the north of the area with silty shales deposited within a sabkha environment. Hydrocarbons were sourced from the underlying Carboniferous Westphahan coals and carbonaceous shales, and migration into the Rotliegendes Group probably occurred during the Late Cretaceous to Early Tertiary.The average daily production from the original Viking A and B fields and associated satellites had declined to 196 MMSCF/D by March 1989, peaking to over 300 MMSCF/D with seasonal demand. By October 1999, this had further reduced to around 40 MMSCF/D. Production from the Phoenix wells is currently at around 290 MMSCF/D, with further development wells planned. Cumulative production to date is approximately 2880 BCF.

The Douglas Field, Block 110/13b, UK East Irish Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 307-319 ◽  
Author(s):  
J. Bunce
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Column Height ◽  
Irish Sea ◽  
Artificial Lift ◽  
Water Alternating Gas ◽  
Stock Tank ◽  
Light Oil ◽  
Sandstone Formation ◽  
Water Cut

AbstractThe Douglas Field is located in Block 110/13b in the East Irish Sea. It was the first oilfield to be discovered and produced in the region, having been found in 1990 and brought on stream in January 1996. The field structure comprises a series of north–south-trending, tilted, extensional fault blocks. The reservoir interval is the Triassic Ormskirk Sandstone Formation comprising good quality aeolian and fluvial sandstones. The field is relatively shallow, with the top reservoir at c. 2120 ft true vertical depth subsea. The hydrocarbon is a light oil of 44°API gravity with a maximum column height of c. 400 ft. The Douglas Field contains an estimated stock tank oil in place of 248 MMbbl and was developed with 22 wells: 15 producers, six water injectors and a single sour gas and condensate disposal well. Electric submersible pumps are installed in oil producers for artificial lift and water injection was utilized from field start-up for pressure maintenance. A water-alternating-gas pilot was implemented on the field in 2017 as an enhanced oil recovery scheme. The field currently produces at a rate of c. 4000 bopd, with approximately 90% water cut. The field has produced 103 MMbbl to date, giving a current oil recovery of c. 41%.

Depositional Environment Drive as Overpressure Generation: Study Case in “Gap” Field, North West Java Basin

2020 ◽  
Author(s):  
A., C. Prasetyo
Keyword(s):  
Clay Mineral ◽  
Depositional Environment ◽  
Mineral Content ◽  
Hydrocarbon Generation ◽  
Well Test ◽  
Burial History ◽  
The South ◽  
North West ◽  
The North ◽  
Geological Processes

Overpressure existence represents a geological hazard; therefore, an accurate pore pressure prediction is critical for well planning and drilling procedures, etc. Overpressure is a geological phenomenon usually generated by two mechanisms, loading (disequilibrium compaction) and unloading mechanisms (diagenesis and hydrocarbon generation) and they are all geological processes. This research was conducted based on analytical and descriptive methods integrated with well data including wireline log, laboratory test and well test data. This research was conducted based on quantitative estimate of pore pressures using the Eaton Method. The stages are determining shale intervals with GR logs, calculating vertical stress/overburden stress values, determining normal compaction trends, making cross plots of sonic logs against density logs, calculating geothermal gradients, analyzing hydrocarbon maturity, and calculating sedimentation rates with burial history. The research conducted an analysis method on the distribution of clay mineral composition to determine depositional environment and its relationship to overpressure. The wells include GAP-01, GAP-02, GAP-03, and GAP-04 which has an overpressure zone range at depth 8501-10988 ft. The pressure value within the 4 wells has a range between 4358-7451 Psi. Overpressure mechanism in the GAP field is caused by non-loading mechanism (clay mineral diagenesis and hydrocarbon maturation). Overpressure distribution is controlled by its stratigraphy. Therefore, it is possible overpressure is spread quite broadly, especially in the low morphology of the “GAP” Field. This relates to the delta depositional environment with thick shale. Based on clay minerals distribution, the northern part (GAP 02 & 03) has more clay mineral content compared to the south and this can be interpreted increasingly towards sea (low energy regime) and facies turned into pro-delta. Overpressure might be found shallower in the north than the south due to higher clay mineral content present to the north.

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